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



[[Page 38481]]

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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  

[[Page 38482]]


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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 
[email protected].

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 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

[[Page 38483]]

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).

[[Page 38484]]

 
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 (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

[[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 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-

[[Page 38491]]

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.

[[Page 38492]]

    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

[[Page 38493]]

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

[[Page 38494]]

(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, 12.5.2.2.3.
    (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 
12.5.2.2.3.
    (11) ASTM D270-65, 75, Standard Method of Sampling Petroleum and 
Petroleum Products, IBR approved for Appendix A: Method 19, Section 
12.5.2.2.1.
    (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,

[[Page 38495]]

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 12.5.2.2.3.
    (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 12.3.2.4.
    (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 
12.5.2.1.3.
    (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 12.5.2.1.3.
    (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 
12.5.2.1.1.
    (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 7.1.1.2.
    (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 12.5.2.1.3.
    (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 12.3.2.3.
    (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 12.5.2.1.3.
    (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).

[[Page 38496]]

    (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 12.5.2.1.3.
    (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 12.5.2.2.3.
    (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 12.5.2.2.1.
    (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 
12.5.2.1.3.
    (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 12.5.2.1.3.
    (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

[[Page 38497]]

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.

[[Page 38498]]

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

[[Page 38499]]

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 
identify excess emissions under this subpart. Periods where the missing 
data substitution procedures in subpart D of part 75 are applied are to 
be reported as monitor downtime in the excess emissions and monitoring 
performance report required under Sec.  60.7(c).
    (e) All required fuel flow rate, steam flow rate, temperature, 
pressure, and megawatt data must be reduced to hourly averages.
    (f) Calculate the hourly average NOX emission rates, in 
units of the emission standards under Sec.  60.4320, using either ppm 
for units complying with the concentration limit or the following 
equation for units complying with the output based standard:
    (1) For simple-cycle operation:
    [GRAPHIC] [TIFF OMITTED] TR06JY06.000
    
Where:

E = hourly NOX emission rate, in lb/MWh,
(NOX)h = hourly NOX emission rate, 
in lb/MMBtu,
(HI)h = hourly heat input rate to the unit, in MMBtu/h, 
measured using the fuel flowmeter(s), e.g., calculated using 
Equation D-15a in appendix D to part 75 of this chapter, and
P = gross energy output of the combustion turbine in MW.

    (2) For combined-cycle and combined heat and power complying with 
the output-based standard, use Equation 1 of this subpart, except that 
the gross energy output is calculated as the sum of the total 
electrical and mechanical energy generated by the combustion turbine, 
the additional electrical or mechanical energy (if any) generated by 
the steam turbine following the heat recovery steam generator, and 100 
percent of the total useful thermal energy output that is not used to 
generate additional electricity or mechanical output, expressed in 
equivalent MW, as in the following equations:
[GRAPHIC] [TIFF OMITTED] TR06JY06.001

Where:

P = gross energy output of the stationary combustion turbine system 
in MW.
(Pe)t = electrical or mechanical energy output of the 
combustion turbine in MW,
(Pe)c = electrical or mechanical energy output (if any) 
of the steam turbine in MW, and
[GRAPHIC] [TIFF OMITTED] TR06JY06.002

Where:

Ps = useful thermal energy of the steam, measured relative to ISO 
conditions, not used to generate additional electric or mechanical 
output, in MW,
Q = measured steam flow rate in lb/h,
H = enthalpy of the steam at measured temperature and pressure 
relative to ISO conditions, in Btu/lb, and 3.413 x 106 = 
conversion from Btu/h to MW.


    Po = other useful heat recovery, measured relative to ISO 
conditions, not used for steam generation or performance enhancement 
of the combustion turbine.

    (3) For mechanical drive applications complying with the output-
based standard, use the following equation:
[GRAPHIC] [TIFF OMITTED] TR06JY06.003


Where:

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

    (g) For simple cycle units without heat recovery, use the 
calculated hourly average emission rates from paragraph (f) of this 
section to assess excess emissions on a 4-hour rolling average basis, 
as described in Sec.  60.4380(b)(1).

[[Page 38500]]

    (h) For combined cycle and combined heat and power units with heat 
recovery, use the calculated hourly average emission rates from 
paragraph (f) of this section to assess excess emissions on a 30 unit 
operating day rolling average basis, as described in Sec.  
60.4380(b)(1).


Sec.  60.4355  How do I establish and document a proper parameter 
monitoring plan?

    (a) The steam or water to fuel ratio or other parameters that are 
continuously monitored as described in Sec. Sec.  60.4335 and 60.4340 
must be monitored during the performance test required under Sec.  
60.8, to establish acceptable values and ranges. You may supplement the 
performance test data with engineering analyses, design specifications, 
manufacturer's recommendations and other relevant information to define 
the acceptable parametric ranges more precisely. You must develop and 
keep on-site a parameter monitoring plan which explains the procedures 
used to document proper operation of the NOX emission 
controls. The plan must:
    (1) Include the indicators to be monitored and show there is a 
significant relationship to emissions and proper operation of the 
NOX emission controls,
    (2) Pick ranges (or designated conditions) of the indicators, or 
describe the process by which such range (or designated condition) will 
be established,
    (3) Explain the process you will use to make certain that you 
obtain data that are representative of the emissions or parameters 
being monitored (such as detector location, installation specification 
if applicable),
    (4) Describe quality assurance and control practices that are 
adequate to ensure the continuing validity of the data,
    (5) Describe the frequency of monitoring and the data collection 
procedures which you will use (e.g., you are using a computerized data 
acquisition over a number of discrete data points with the average (or 
maximum value) being used for purposes of determining whether an 
exceedance has occurred), and
    (6) Submit justification for the proposed elements of the 
monitoring. If a proposed performance specification differs from 
manufacturer recommendation, you must explain the reasons for the 
differences. You must submit the data supporting the justification, but 
you may refer to generally available sources of information used to 
support the justification. You may rely on engineering assessments and 
other data, provided you demonstrate factors which assure compliance or 
explain why performance testing is unnecessary to establish indicator 
ranges. When establishing indicator ranges, you may choose to simplify 
the process by treating the parameters as if they were correlated. 
Using this assumption, testing can be divided into two cases:
    (i) All indicators are significant only on one end of range (e.g., 
for a thermal incinerator controlling volatile organic compounds (VOC) 
it is only important to insure a minimum temperature, not a maximum). 
In this case, you may conduct your study so that each parameter is at 
the significant limit of its range while you conduct your emissions 
testing. If the emissions tests show that the source is in compliance 
at the significant limit of each parameter, then as long as each 
parameter is within its limit, you are presumed to be in compliance.
    (ii) Some or all indicators are significant on both ends of the 
range. In this case, you may conduct your study so that each parameter 
that is significant at both ends of its range assumes its extreme 
values in all possible combinations of the extreme values (either 
single or double) of all of the other parameters. For example, if there 
were only two parameters, A and B, and A had a range of values while B 
had only a minimum value, the combinations would be A high with B 
minimum and A low with B minimum. If both A and B had a range, the 
combinations would be A high and B high, A low and B low, A high and B 
low, A low and B high. For the case of four parameters all having a 
range, there are 16 possible combinations.
    (b) For affected units that are also subject to part 75 of this 
chapter and that have state approval to use the low mass emissions 
methodology in Sec.  75.19 or the NOX emission measurement 
methodology in appendix E to part 75, you may meet the requirements of 
this paragraph by developing and keeping on-site (or at a central 
location for unmanned facilities) a QA plan, as described in Sec.  
75.19(e)(5) or in section 2.3 of appendix E to part 75 of this chapter 
and section 1.3.6 of appendix B to part 75 of this chapter.


Sec.  60.4360  How do I determine the total sulfur content of the 
turbine's combustion fuel?

    You must monitor the total sulfur content of the fuel being fired 
in the turbine, except as provided in Sec.  60.4365. The sulfur content 
of the fuel must be determined using total sulfur methods described in 
Sec.  60.4415. Alternatively, if the total sulfur content of the 
gaseous fuel during the most recent performance test was less than half 
the applicable limit, ASTM D4084, D4810, D5504, or D6228, or Gas 
Processors Association Standard 2377 (all of which are incorporated by 
reference, see Sec.  60.17), which measure the major sulfur compounds, 
may be used.


Sec.  60.4365  How can I be exempted from monitoring the total sulfur 
content of the fuel?

    You may elect not to monitor the total sulfur content of the fuel 
combusted in the turbine, if the fuel is demonstrated not to exceed 
potential sulfur emissions of 26 ng SO2/J (0.060 lb 
SO2/MMBtu) heat input for units located in continental areas 
and 180 ng SO2/J (0.42 lb SO2/MMBtu) heat input 
for units located in noncontinental areas 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 use one of the following sources of 
information to make the required demonstration:
    (a) The fuel quality characteristics in a current, valid purchase 
contract, tariff sheet or transportation contract for the fuel, 
specifying that the maximum total sulfur content for oil use in 
continental areas is 0.05 weight percent (500 ppmw) or less and 0.4 
weight percent (4,000 ppmw) or less for noncontinental areas, the total 
sulfur content for natural gas use in continental areas is 20 grains of 
sulfur or less per 100 standard cubic feet and 140 grains of sulfur or 
less per 100 standard cubic feet for noncontinental areas, has 
potential sulfur emissions of less than less than 26 ng SO2/
J (0.060 lb SO2/MMBtu) heat input for continental areas and 
has potential sulfur emissions of less than less than 180 ng 
SO2/J (0.42 lb SO2/MMBtu) heat input for 
noncontinental areas; or
    (b) Representative fuel sampling data which show that the sulfur 
content of the fuel does not exceed 26 ng SO2/J (0.060 lb 
SO2/MMBtu) heat input for continental areas or 180 ng 
SO2/J (0.42 lb SO2/MMBtu) heat input for 
noncontinental areas. At a minimum, the amount of fuel sampling data 
specified in section 2.3.1.4 or 2.3.2.4 of appendix D to part 75 of 
this chapter is required.


Sec.  60.4370  How often must I determine the sulfur content of the 
fuel?

    The frequency of determining the sulfur content of the fuel must be 
as follows:
    (a) Fuel oil. For fuel oil, use one of the total sulfur sampling 
options and the

[[Page 38501]]

associated sampling frequency described in sections 2.2.3, 2.2.4.1, 
2.2.4.2, and 2.2.4.3 of appendix D to part 75 of this chapter (i.e., 
flow proportional sampling, daily sampling, sampling from the unit's 
storage tank after each addition of fuel to the tank, or sampling each 
delivery prior to combining it with fuel oil already in the intended 
storage tank).
    (b) Gaseous fuel. If you elect not to demonstrate sulfur content 
using options in Sec.  60.4365, and the fuel is supplied without 
intermediate bulk storage, the sulfur content value of the gaseous fuel 
must be determined and recorded once per unit operating day.
    (c) Custom schedules. Notwithstanding the requirements of paragraph 
(b) of this section, operators or fuel vendors may develop custom 
schedules for determination of the total sulfur content of gaseous 
fuels, based on the design and operation of the affected facility and 
the characteristics of the fuel supply. Except as provided in 
paragraphs (c)(1) and (c)(2) of this section, custom schedules shall be 
substantiated with data and shall be approved by the Administrator 
before they can be used to comply with the standard in Sec.  60.4330.
    (1) The two custom sulfur monitoring schedules set forth in 
paragraphs (c)(1)(i) through (iv) and in paragraph (c)(2) of this 
section are acceptable, without prior Administrative approval:
    (i) The owner or operator shall obtain daily total sulfur content 
measurements for 30 consecutive unit operating days, using the 
applicable methods specified in this subpart. Based on the results of 
the 30 daily samples, the required frequency for subsequent monitoring 
of the fuel's total sulfur content shall be as specified in paragraph 
(c)(1)(ii), (iii), or (iv) of this section, as applicable.
    (ii) If none of the 30 daily measurements of the fuel's total 
sulfur content exceeds half the applicable standard, subsequent sulfur 
content monitoring may be performed at 12-month intervals. If any of 
the samples taken at 12-month intervals has a total sulfur content 
greater than half but less than the applicable limit, follow the 
procedures in paragraph (c)(1)(iii) of this section. If any measurement 
exceeds the applicable limit, follow the procedures in paragraph 
(c)(1)(iv) of this section.
    (iii) If at least one of the 30 daily measurements of the fuel's 
total sulfur content is greater than half but less than the applicable 
limit, but none exceeds the applicable limit, then:
    (A) Collect and analyze a sample every 30 days for 3 months. If any 
sulfur content measurement exceeds the applicable limit, follow the 
procedures in paragraph (c)(1)(iv) of this section. Otherwise, follow 
the procedures in paragraph (c)(1)(iii)(B) of this section.
    (B) Begin monitoring at 6-month intervals for 12 months. If any 
sulfur content measurement exceeds the applicable limit, follow the 
procedures in paragraph (c)(1)(iv) of this section. Otherwise, follow 
the procedures in paragraph (c)(1)(iii)(C) of this section.
    (C) Begin monitoring at 12-month intervals. If any sulfur content 
measurement exceeds the applicable limit, follow the procedures in 
paragraph (c)(1)(iv) of this section. Otherwise, continue to monitor at 
this frequency.
    (iv) If a sulfur content measurement exceeds the applicable limit, 
immediately begin daily monitoring according to paragraph (c)(1)(i) of 
this section. Daily monitoring shall continue until 30 consecutive 
daily samples, each having a sulfur content no greater than the 
applicable limit, are obtained. At that point, the applicable 
procedures of paragraph (c)(1)(ii) or (iii) of this section shall be 
followed.
    (2) The owner or operator may use the data collected from the 720-
hour sulfur sampling demonstration described in section 2.3.6 of 
appendix D to part 75 of this chapter to determine a custom sulfur 
sampling schedule, as follows:
    (i) If the maximum fuel sulfur content obtained from the 720 hourly 
samples does not exceed 20 grains/100 scf, no additional monitoring of 
the sulfur content of the gas is required, for the purposes of this 
subpart.
    (ii) If the maximum fuel sulfur content obtained from any of the 
720 hourly samples exceeds 20 grains/100 scf, but none of the sulfur 
content values (when converted to weight percent sulfur) exceeds half 
the applicable limit, then the minimum required sampling frequency 
shall be one sample at 12 month intervals.
    (iii) If any sample result exceeds half the applicable limit, but 
none exceeds the applicable limit, follow the provisions of paragraph 
(c)(1)(iii) of this section.
    (iv) If the sulfur content of any of the 720 hourly samples exceeds 
the applicable limit, follow the provisions of paragraph (c)(1)(iv) of 
this section.

Reporting


Sec.  60.4375  What reports must I submit?

    (a) For each affected unit required to continuously monitor 
parameters or emissions, or to periodically determine the fuel sulfur 
content under this subpart, you must submit reports of excess emissions 
and monitor downtime, in accordance with Sec.  60.7(c). Excess 
emissions must be reported for all periods of unit operation, including 
start-up, shutdown, and malfunction.
    (b) For each affected unit that performs annual performance tests 
in accordance with Sec.  60.4340(a), you must submit a written report 
of the results of each performance test before the close of business on 
the 60th day following the completion of the performance test.


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

    For the purpose of reports required under Sec.  60.7(c), periods of 
excess emissions and monitor downtime that must be reported are defined 
as follows:
    (a) For turbines using water or steam to fuel ratio monitoring:
    (1) An excess emission is any unit operating hour for which the 4-
hour rolling average steam or water to fuel ratio, as measured by the 
continuous monitoring system, falls below the acceptable steam or water 
to fuel ratio needed to demonstrate compliance with Sec.  60.4320, as 
established during the performance test required in Sec.  60.8. Any 
unit operating hour in which no water or steam is injected into the 
turbine when a fuel is being burned that requires water or steam 
injection for NOX control will also be considered an excess 
emission.
    (2) A period of monitor downtime is any unit operating hour in 
which water or steam is injected into the turbine, but the essential 
parametric data needed to determine the steam or water to fuel ratio 
are unavailable or invalid.
    (3) Each report must include the average steam or water to fuel 
ratio, average fuel consumption, and the combustion turbine load during 
each excess emission.
    (b) For turbines using continuous emission monitoring, as described 
in Sec. Sec.  60.4335(b) and 60.4345:
    (1) An excess emissions is any unit operating period in which the 
4-hour or 30-day rolling average NOX emission rate exceeds 
the applicable emission limit in Sec.  60.4320. For the purposes of 
this subpart, a ``4-hour rolling average NOX emission rate'' 
is the arithmetic average of the average NOX emission rate 
in ppm or ng/J (lb/MWh) measured by the continuous emission monitoring 
equipment for a given hour and the three unit operating hour average 
NOX emission rates immediately preceding that unit operating 
hour. Calculate the rolling average if a valid NOX emission 
rate is obtained for at least 3 of the 4 hours. For the purposes of 
this subpart, a ``30-day rolling average NOX emission rate'' 
is the arithmetic average of all hourly NOX emission data in 
ppm or

[[Page 38502]]

ng/J (lb/MWh) measured by the continuous emission monitoring equipment 
for a given day and the twenty-nine unit operating days immediately 
preceding that unit operating day. A new 30-day average is calculated 
each unit operating day as the average of all hourly NOX 
emissions rates for the preceding 30 unit operating days if a valid 
NOX emission rate is obtained for at least 75 percent of all 
operating hours.
    (2) A period of monitor downtime is any unit operating hour in 
which the data for any of the following parameters are either missing 
or invalid: NOX concentration, CO2 or 
O2 concentration, fuel flow rate, steam flow rate, steam 
temperature, steam pressure, or megawatts. The steam flow rate, steam 
temperature, and steam pressure are only required if you will use this 
information for compliance purposes.
    (3) For operating periods during which multiple emissions standards 
apply, the applicable standard is the average of the applicable 
standards during each hour. For hours with multiple emissions 
standards, the applicable limit for that hour is determined based on 
the condition that corresponded to the highest emissions standard.
    (c) For turbines required to monitor combustion parameters or 
parameters that document proper operation of the NOX 
emission controls:
    (1) An excess emission is a 4-hour rolling unit operating hour 
average in which any monitored parameter does not achieve the target 
value or is outside the acceptable range defined in the parameter 
monitoring plan for the unit.
    (2) A period of monitor downtime is a unit operating hour in which 
any of the required parametric data are either not recorded or are 
invalid.


Sec.  60.4385  How are excess emissions and monitoring downtime defined 
for SO2?

    If you choose the option to monitor the sulfur content of the fuel, 
excess emissions and monitoring downtime are defined as follows:
    (a) For samples of gaseous fuel and for oil samples obtained using 
daily sampling, flow proportional sampling, or sampling from the unit's 
storage tank, an excess emission occurs each unit operating hour 
included in the period beginning on the date and hour of any sample for 
which the sulfur content of the fuel being fired in the combustion 
turbine exceeds the applicable limit and ending on the date and hour 
that a subsequent sample is taken that demonstrates compliance with the 
sulfur limit.
    (b) If the option to sample each delivery of fuel oil has been 
selected, you must immediately switch to one of the other oil sampling 
options (i.e., daily sampling, flow proportional sampling, or sampling 
from the unit's storage tank) if the sulfur content of a delivery 
exceeds 0.05 weight percent. You must continue to use one of the other 
sampling options until all of the oil from the delivery has been 
combusted, and you must evaluate excess emissions according to 
paragraph (a) of this section. When all of the fuel from the delivery 
has been burned, you may resume using the as-delivered sampling option.
    (c) A period of monitor downtime begins when a required sample is 
not taken by its due date. A period of monitor downtime also begins on 
the date and hour of a required sample, if invalid results are 
obtained. The period of monitor downtime ends on the date and hour of 
the next valid sample.


Sec.  60.4390  What are my reporting requirements if I operate an 
emergency combustion turbine or a research and development turbine?

    (a) If you operate an emergency combustion turbine, you are exempt 
from the NOX limit and must submit an initial report to the 
Administrator stating your case.
    (b) Combustion turbines engaged by manufacturers in research and 
development of equipment for both combustion turbine emission control 
techniques and combustion turbine efficiency improvements may be 
exempted from the NOX limit on a case-by-case basis as 
determined by the Administrator. You must petition for the exemption.


Sec.  60.4395  When must I submit my reports?

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

Performance Tests


Sec.  60.4400  How do I conduct the initial and subsequent performance 
tests, regarding NOX?

    (a) You must conduct an initial performance test, as required in 
Sec.  60.8. Subsequent NOX performance tests shall be 
conducted on an annual basis (no more than 14 calendar months following 
the previous performance test).
    (1) There are two general methodologies that you may use to conduct 
the performance tests. For each test run:
    (i) Measure the NOX concentration (in parts per million 
(ppm)), using EPA Method 7E or EPA Method 20 in appendix A of this 
part. For units complying with the output based standard, concurrently 
measure the stack gas flow rate, using EPA Methods 1 and 2 in appendix 
A of this part, and measure and record the electrical and thermal 
output from the unit. Then, use the following equation to calculate the 
NOX emission rate:
[GRAPHIC] [TIFF OMITTED] TR06JY06.004

Where:

E = NOX emission rate, in lb/MWh
1.194 x 10-7 = conversion constant, in lb/dscf-ppm
(NOX)c = average NOX concentration 
for the run, in ppm
Qstd = stack gas volumetric flow rate, in dscf/hr
P = gross electrical and mechanical energy output of the combustion 
turbine, in MW (for simple-cycle operation), for combined-cycle 
operation, the sum of all electrical and mechanical output from the 
combustion and steam turbines, or, for combined heat and power 
operation, the sum of all electrical and mechanical output from the 
combustion and steam turbines plus all useful recovered thermal 
output not used for additional electric or mechanical generation, in 
MW, calculated according to Sec.  60.4350(f)(2); or

    (ii) Measure the NOX and diluent gas concentrations, 
using either EPA Methods 7E and 3A, or EPA Method 20 in appendix A of 
this part. Concurrently measure the heat input to the unit, using a 
fuel flowmeter (or flowmeters), and measure the electrical and thermal 
output of the unit. Use EPA Method 19 in appendix A of this part to 
calculate the NOX emission rate in lb/MMBtu. Then, use 
Equations 1 and, if necessary, 2 and 3 in Sec.  60.4350(f) to calculate 
the NOX emission rate in lb/MWh.

[[Page 38503]]

    (2) Sampling traverse points for NOX and (if applicable) 
diluent gas are to be selected following EPA Method 20 or EPA Method 1 
(non-particulate procedures), and sampled for equal time intervals. The 
sampling must be performed with a traversing single-hole probe, or, if 
feasible, with a stationary multi-hole probe that samples each of the 
points sequentially. Alternatively, a multi-hole probe designed and 
documented to sample equal volumes from each hole may be used to sample 
simultaneously at the required points.
    (3) Notwithstanding paragraph (a)(2) of this section, you may test 
at fewer points than are specified in EPA Method 1 or EPA Method 20 in 
appendix A of this part if the following conditions are met:
    (i) You may perform a stratification test for NOX and 
diluent pursuant to
    (A) [Reserved], or
    (B) The procedures specified in section 6.5.6.1(a) through (e) of 
appendix A of part 75 of this chapter.
    (ii) Once the stratification sampling is completed, you may use the 
following alternative sample point selection criteria for the 
performance test:
    (A) If each of the individual traverse point NOX 
concentrations is within 10 percent of the mean 
concentration for all traverse points, or the individual traverse point 
diluent concentrations differs by no more than 5ppm or 
0.5 percent CO2 (or O2) from the mean 
for all traverse points, then you may use three points (located either 
16.7, 50.0 and 83.3 percent of the way across the stack or duct, or, 
for circular stacks or ducts greater than 2.4 meters (7.8 feet) in 
diameter, at 0.4, 1.2, and 2.0 meters from the wall). The three points 
must be located along the measurement line that exhibited the highest 
average NOX concentration during the stratification test; or
    (B) For turbines with a NOX standard greater than 15 ppm 
@ 15% O2, you may sample at a single point, located at least 
1 meter from the stack wall or at the stack centroid if each of the 
individual traverse point NOX concentrations is within 
5 percent of the mean concentration for all traverse 
points, or the individual traverse point diluent concentrations differs 
by no more than 3ppm or 0.3 percent 
CO2 (or O2) from the mean for all traverse 
points; or
    (C) For turbines with a NOX standard less than or equal 
to 15 ppm @ 15% O2, you may sample at a single point, 
located at least 1 meter from the stack wall or at the stack centroid 
if each of the individual traverse point NOX concentrations 
is within 2.5 percent of the mean concentration for all 
traverse points, or the individual traverse point diluent 
concentrations differs by no more than 1ppm or 0.15 percent CO2 (or O2) from the mean for 
all traverse points.
    (b) The performance test must be done at any load condition within 
plus or minus 25 percent of 100 percent of peak load. You may perform 
testing at the highest achievable load point, if at least 75 percent of 
peak load cannot be achieved in practice. You must conduct three 
separate test runs for each performance test. The minimum time per run 
is 20 minutes.
    (1) If the stationary combustion turbine combusts both oil and gas 
as primary or backup fuels, separate performance testing is required 
for each fuel.
    (2) For a combined cycle and CHP turbine systems with supplemental 
heat (duct burner), you must measure the total NOX emissions 
after the duct burner rather than directly after the turbine. The duct 
burner must be in operation during the performance test.
    (3) If water or steam injection is used to control NOX 
with no additional post-combustion NOX control and you 
choose to monitor the steam or water to fuel ratio in accordance with 
Sec.  60.4335, then that monitoring system must be operated 
concurrently with each EPA Method 20 or EPA Method 7E run and must be 
used to determine the fuel consumption and the steam or water to fuel 
ratio necessary to comply with the applicable Sec.  60.4320 
NOX emission limit.
    (4) Compliance with the applicable emission limit in Sec.  60.4320 
must be demonstrated at each tested load level. Compliance is achieved 
if the three-run arithmetic average NOX emission rate at 
each tested level meets the applicable emission limit in Sec.  60.4320.
    (5) If you elect to install a CEMS, the performance evaluation of 
the CEMS may either be conducted separately or (as described in Sec.  
60.4405) as part of the initial performance test of the affected unit.
    (6) The ambient temperature must be greater than 0 [deg]F during 
the performance test.


Sec.  60.4405  How do I perform the initial performance test if I have 
chosen to install a NOX-diluent CEMS?

    If you elect to install and certify a NOX-diluent CEMS 
under Sec.  60.4345, then the initial performance test required under 
Sec.  60.8 may be performed in the following alternative manner:
    (a) Perform a minimum of nine RATA reference method runs, with a 
minimum time per run of 21 minutes, at a single load level, within plus 
or minus 25 percent of 100 percent of peak load. The ambient 
temperature must be greater than 0 [deg]F during the RATA runs.
    (b) For each RATA run, concurrently measure the heat input to the 
unit using a fuel flow meter (or flow meters) and measure the 
electrical and thermal output from the unit.
    (c) Use the test data both to demonstrate compliance with the 
applicable NOX emission limit under Sec.  60.4320 and to 
provide the required reference method data for the RATA of the CEMS 
described under Sec.  60.4335.
    (d) Compliance with the applicable emission limit in Sec.  60.4320 
is achieved if the arithmetic average of all of the NOX 
emission rates for the RATA runs, expressed in units of ppm or lb/MWh, 
does not exceed the emission limit.


Sec.  60.4410  How do I establish a valid parameter range if I have 
chosen to continuously monitor parameters?

    If you have chosen to monitor combustion parameters or parameters 
indicative of proper operation of NOX emission controls in 
accordance with Sec.  60.4340, the appropriate parameters must be 
continuously monitored and recorded during each run of the initial 
performance test, to establish acceptable operating ranges, for 
purposes of the parameter monitoring plan for the affected unit, as 
specified in Sec.  60.4355.


Sec.  60.4415  How do I conduct the initial and subsequent performance 
tests for sulfur?

    (a) You must conduct an initial performance test, as required in 
Sec.  60.8. Subsequent SO2 performance tests shall be 
conducted on an annual basis (no more than 14 calendar months following 
the previous performance test). There are three methodologies that you 
may use to conduct the performance tests.
    (1) If you choose to periodically determine the sulfur content of 
the fuel combusted in the turbine, a representative fuel sample would 
be collected following ASTM D5287 (incorporated by reference, see Sec.  
60.17) for natural gas or ASTM D4177 (incorporated by reference, see 
Sec.  60.17) for oil. Alternatively, for oil, you may follow the 
procedures for manual pipeline sampling in section 14 of ASTM D4057 
(incorporated by reference, see Sec.  60.17). The fuel analyses of this 
section may be performed either by you, a service contractor retained 
by you, the fuel vendor, or any other qualified agency. Analyze the 
samples for the total sulfur content of the fuel using:
    (i) For liquid fuels, ASTM D129, or alternatively D1266, D1552, 
D2622, D4294, or D5453 (all of which are incorporated by reference, see 
Sec.  60.17); or

[[Page 38504]]

    (ii) For gaseous fuels, ASTM D1072, or alternatively D3246, D4084, 
D4468, D4810, D6228, D6667, or Gas Processors Association Standard 2377 
(all of which are incorporated by reference, see Sec.  60.17).
    (2) Measure the SO2 concentration (in parts per million 
(ppm)), using EPA Methods 6, 6C, 8, or 20 in appendix A of this part. 
In addition, the American Society of Mechanical Engineers (ASME) 
standard, ASME PTC 19-10-1981-Part 10, ``Flue and Exhaust Gas 
Analyses,'' manual methods for sulfur dioxide (incorporated by 
reference, see Sec.  60.17) can be used instead of EPA Methods 6 or 20. 
For units complying with the output based standard, concurrently 
measure the stack gas flow rate, using EPA Methods 1 and 2 in appendix 
A of this part, and measure and record the electrical and thermal 
output from the unit. Then use the following equation to calculate the 
SO2 emission rate:
[GRAPHIC] [TIFF OMITTED] TR06JY06.005

Where:

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

    (3) Measure the SO2 and diluent gas concentrations, 
using either EPA Methods 6, 6C, or 8 and 3A, or 20 in appendix A of 
this part. In addition, you may use the manual methods for sulfur 
dioxide ASME PTC 19-10-1981-Part 10 (incorporated by reference, see 
Sec.  60.17). Concurrently measure the heat input to the unit, using a 
fuel flowmeter (or flowmeters), and measure the electrical and thermal 
output of the unit. Use EPA Method 19 in appendix A of this part to 
calculate the SO2 emission rate in lb/MMBtu. Then, use 
Equations 1 and, if necessary, 2 and 3 in Sec.  60.4350(f) to calculate 
the SO2 emission rate in lb/MWh.
    (b) [Reserved]

Definitions


Sec.  60.4420  What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein will have the 
meaning given them in the Clean Air Act and in subpart A (General 
Provisions) of this part.
    Combined cycle combustion turbine means any stationary combustion 
turbine which recovers heat from the combustion turbine exhaust gases 
to generate steam that is only used to create additional power output 
in a steam turbine.
    Combined heat and power combustion turbine means any stationary 
combustion turbine which recovers heat from the exhaust gases to heat 
water or another medium, generate steam for useful purposes other than 
additional electric generation, or directly uses the heat in the 
exhaust gases for a useful purpose.
    Combustion turbine model means a group of combustion turbines 
having the same nominal air flow, combustor inlet pressure, combustor 
inlet temperature, firing temperature, turbine inlet temperature and 
turbine inlet pressure.
    Combustion turbine test cell/stand means any apparatus used for 
testing uninstalled stationary or uninstalled mobile (motive) 
combustion turbines.
    Diffusion flame stationary combustion turbine means any stationary 
combustion turbine where fuel and air are injected at the combustor and 
are mixed only by diffusion prior to ignition.
    Duct burner means a device that combusts fuel and that is placed in 
the exhaust duct from another source, such as a stationary combustion 
turbine, internal combustion engine, kiln, etc., to allow the firing of 
additional fuel to heat the exhaust gases before the exhaust gases 
enter a heat recovery steam generating unit.
    Efficiency means the combustion turbine manufacturer's rated heat 
rate at peak load in terms of heat input per unit of power output--
based on the higher heating value of the fuel.
    Emergency combustion turbine means any stationary combustion 
turbine which operates in an emergency situation. Examples include 
stationary combustion turbines used to produce power for critical 
networks or equipment, including power supplied to portions of a 
facility, when electric power from the local utility is interrupted, or 
stationary combustion turbines used to pump water in the case of fire 
or flood, etc. Emergency stationary combustion turbines do not include 
stationary combustion turbines used as peaking units at electric 
utilities or stationary combustion turbines at industrial facilities 
that typically operate at low capacity factors. Emergency combustion 
turbines may be operated for the purpose of maintenance checks and 
readiness testing, provided that the tests are required by the 
manufacturer, the vendor, or the insurance company associated with the 
turbine. Required testing of such units should be minimized, but there 
is no time limit on the use of emergency combustion turbines.
    Excess emissions means a specified averaging period over which 
either (1) the NOX emissions are higher than the applicable 
emission limit in Sec.  60.4320; (2) the total sulfur content of the 
fuel being combusted in the affected facility exceeds the limit 
specified in Sec.  60.4330; or (3) the recorded value of a particular 
monitored parameter is outside the acceptable range specified in the 
parameter monitoring plan for the affected unit.
    Gross useful output means the gross useful work performed by the 
stationary combustion turbine system. For units using the mechanical 
energy directly or generating only electricity, the gross useful work 
performed is the gross electrical or mechanical output from the 
turbine/generator set. For combined heat and power units, the gross 
useful work performed is the gross electrical or mechanical output plus 
the useful thermal output (i.e., thermal energy delivered to a 
process).
    Heat recovery steam generating unit means a unit where the hot 
exhaust gases from the combustion turbine are routed in order to 
extract heat from the gases and generate steam, for use in a steam 
turbine or other device that utilizes steam. Heat recovery steam 
generating units can be used with or without duct burners.
    Integrated gasification combined cycle electric utility steam 
generating unit means a coal-fired electric utility steam generating 
unit that burns a synthetic gas derived from coal in a

[[Page 38505]]

combined-cycle gas turbine. No solid coal is directly burned in the 
unit during operation.
    ISO conditions means 288 Kelvin, 60 percent relative humidity and 
101.3 kilopascals pressure.
    Lean premix stationary combustion turbine means any stationary 
combustion turbine where the air and fuel are thoroughly mixed to form 
a lean mixture before delivery to the combustor. Mixing may occur 
before or in the combustion chamber. A lean premixed turbine may 
operate in diffusion flame mode during operating conditions such as 
startup and shutdown, extreme ambient temperature, or low or transient 
load.
    Natural gas means a naturally occurring fluid mixture of 
hydrocarbons (e.g., methane, ethane, or propane) produced in geological 
formations beneath the Earth's surface that maintains a gaseous state 
at standard atmospheric temperature and pressure under ordinary 
conditions. Additionally, natural gas must either be composed of at 
least 70 percent methane by volume or have a gross calorific value 
between 950 and 1,100 British thermal units (Btu) per standard cubic 
foot. Natural gas does not include the following gaseous fuels: 
landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, 
coal-derived gas, producer gas, coke oven gas, or any gaseous fuel 
produced in a process which might result in highly variable sulfur 
content or heating value.
    Noncontinental area means the State of Hawaii, the Virgin Islands, 
Guam, American Samoa, the Commonwealth of Puerto Rico, the Northern 
Mariana Islands, or offshore platforms.
    Peak load means 100 percent of the manufacturer's design capacity 
of the combustion turbine at ISO conditions.
    Regenerative cycle combustion turbine means any stationary 
combustion turbine which recovers heat from the combustion turbine 
exhaust gases to preheat the inlet combustion air to the combustion 
turbine.
    Simple cycle combustion turbine means any stationary combustion 
turbine which does not recover heat from the combustion turbine exhaust 
gases to preheat the inlet combustion air to the combustion turbine, or 
which does not recover heat from the combustion turbine exhaust gases 
for purposes other than enhancing the performance of the combustion 
turbine itself.
    Stationary combustion turbine means all equipment, including but 
not limited to the 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.
    Unit operating day means a 24-hour period between 12 midnight and 
the following midnight during which any fuel is combusted at any time 
in the unit. It is not necessary for fuel to be combusted continuously 
for the entire 24-hour period.
    Unit operating hour means a clock hour during which any fuel is 
combusted in the affected unit. If the unit combusts fuel for the 
entire clock hour, it is considered to be a full unit operating hour. 
If the unit combusts fuel for only part of the clock hour, it is 
considered to be a partial unit operating hour.
    Useful thermal output means the thermal energy made available for 
use in any industrial or commercial process, or used in any heating or 
cooling application, i.e., total thermal energy made available for 
processes and applications other than electrical or mechanical 
generation. Thermal output for this subpart means the energy in 
recovered thermal output measured against the energy in the thermal 
output at 15 degrees Celsius and 101.325 kilopascals of pressure.

  Table 1.--to Subpart KKKK of Part 60.--Nitrogen Oxide Emission Limits
                 for New Stationary Combustion Turbines
------------------------------------------------------------------------
                               Combustion turbine
   Combustion turbine type     heat input at peak       NOX emission
                                   load (HHV)             standard
------------------------------------------------------------------------
New turbine firing natural    <= 50 MMBtu/h.......  42 ppm at 15 percent
 gas, electric generating.                           O2 or 290 ng/J of
                                                     useful 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).

[[Page 38506]]

 
Turbines located north of     <= 30 MW output.....  150 ppm at 15
 the Arctic Circle (latitude                         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 turbine
 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 turbine
 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).
------------------------------------------------------------------------

[FR Doc. 06-5945 Filed 7-5-06; 8:45 am]
BILLING CODE 6560-50-P