Standards of Performance for Stationary Combustion Turbines, 8314-8332 [05-3000]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 70, Number 33 (Friday, February 18, 2005)]
[Proposed Rules]
[Pages 8314-8332]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 05-3000]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[OAR-2004-0490, FRL-7874-1]
RIN 2060-AM79


Standards of Performance for Stationary Combustion Turbines

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The EPA is proposing standards of performance for new 
stationary combustion turbines in 40 CFR part 60, subpart KKKK. The new 
standards would 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 emission limits up to date 
with the performance of current combustion turbines and their 
emissions.

DATES: Comments must be received on or before April 19, 2005, or 30 
days after the date of any public hearing, if later.
    Public Hearing. If anyone contacts EPA by March 10, 2005, 
requesting to speak at a public hearing, EPA will hold a public hearing 
on March 21, 2005. If you are interested in attending the public 
hearing, contact Ms. Eloise Shepherd at (919) 541-5578 to verify that a 
hearing will be held.

ADDRESSES: Submit your comments, identified by Docket ID No. OAR-2004-
0490, by one of the following methods:
     Federal eRulemaking Portal: https://www.regulations.gov. 
Follow the on-line instructions for submitting comments.
     Agency Web site: https://www.epa.gov/edocket. EDOCKET, 
EPA's electronic public docket and comment system, is EPA's preferred 
method for receiving comments. Follow the on-line instructions for 
submitting comments.
     E-mail: Send your comments via electronic mail to a-and-r-
docket@epa.gov, Attention Docket ID No. OAR-2004-0490.

[[Page 8315]]

     Fax: Fax your comments to (202) 566-1741, Attention Docket 
ID No. OAR-2004-0490.
     Mail: Send your comments to: EPA Docket Center (EPA/DC), 
Environmental Protection Agency, Mailcode 6102T, 1200 Pennsylvania 
Ave., NW., Washington, DC 20460, Attention Docket ID No. OAR-2004-0490. 
Please include a total of two copies. The EPA requests a separate copy 
also be sent to the contact person identified below (see FOR FURTHER 
INFORMATION CONTACT). In addition, please mail a copy of your comments 
on the information collection provisions to the Office of Information 
and Regulatory Affairs, Office of Management and Budget (OMB), Attn: 
Desk Officer for EPA, 725 17th St. NW., Washington, DC 20503.
     Hand Delivery: Deliver your comments to: EPA Docket Center 
(EPA/DC), EPA West Building, Room B108, 1301 Constitution Ave., NW., 
Washington DC, 20460, Attention Docket ID No. OAR-2004-0490. Such 
deliveries are accepted only during the normal hours of operation (8:30 
a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays), 
and special arrangements should be made for deliveries of boxed 
information.
    Instructions: Direct your comments to Docket ID No. OAR-2004-0490. 
The EPA's policy is that all comments received will be included in the 
public docket without change and may be made available online at http:/
/www.epa.gov/edocket, including any personal information provided, 
unless the comment includes information claimed to be Confidential 
Business Information (CBI) or other information whose disclosure is 
restricted by statute. Do not submit information that you consider to 
be CBI or otherwise protected through EDOCKET, regulations.gov, or e-
mail. The EPA EDOCKET and the Federal regulations.gov Web sites are 
``anonymous access'' systems, which means EPA will not know your 
identity or contact information unless you provide it in the body of 
your comment. If you send an e-mail comment directly to EPA without 
going through EDOCKET or regulations.gov, your e-mail address will be 
automatically captured and included as part of the comment that is 
placed in the public docket and made available on the Internet. If you 
submit an electronic comment, EPA recommends that you include your name 
and other contact information in the body of your comment and with any 
disk or CD-ROM you submit. If EPA cannot read your comment due to 
technical difficulties and cannot contact you for clarification, EPA 
may not be able to consider your comment. Electronic files should avoid 
the use of special characters, any form of encryption, and be free of 
any defects or viruses. For additional information about EPA's public 
docket visit EDOCKET on-line or see the Federal Register of May 31, 
2002 (67 FR 38102).
    Docket: All documents in the docket are listed in the EDOCKET index 
at https://www.epa.gov/edocket. Although listed in the index, some 
information is not publicly available, i.e., 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 in EDOCKET or in hard 
copy at the Docket, 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 EPA Docket Center is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Mr. Jaime Pagan, Combustion Group, 
Emission Standards Division (C439-01), U.S. EPA, Research Triangle 
Park, North Carolina 27711; telephone number (919) 541-5340; facsimile 
number (919) 541-5450; e-mail address ``pagan.jaime@epa.gov.''

SUPPLEMENTARY INFORMATION:  Organization of This Document. The 
following outline is provided to aid in locating information in this 
preamble.

I. General Information
    A. Does This Action Apply to Me?
    B. What Should I Consider as I Prepare My Comments for EPA?
II. Background Information
III. Summary of the Proposed Rule
    A. Does the Proposed Rule Apply to Me?
    B. What Pollutants Would Be 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 
Proposed Rule Apply To Me?
    F. How Do I Demonstrate Compliance?
    G. What Monitoring Requirements Must I Meet?
    H. What Reports Must I Submit?
IV. Rationale for the Proposed Rule
    A. Why Did EPA Choose Output-Based Standards?
    B. How Did EPA Determine the Proposed NOX Limits?
    C. How Did EPA Determine the Proposed SO2 Limit?
    D. What Other Criteria Pollutants Did EPA Consider?
    E. How Did EPA Determine Testing and Monitoring Requirements for 
the Proposed Rule?
    F. Why Are Heat Recovery Steam Generators Included in 40 CFR 
part 60, Subpart KKKK?
    G. What Emission Limits Must I Meet if I Fire More Than One Type 
of Fuel?
    H. Why Can I No Longer Claim a Fuel-Bound Nitrogen Allowance?
    I. Why Isn't My IGCC Turbine Covered in 40 CFR Part 60, Subpart 
KKKK?
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

I. General Information

A. Does This Action Apply to Me?

    Regulated Entities. Categories and entities potentially regulated 
by this action are those that own and operate new stationary combustion 
turbines with a peak rated power output greater than or equal to 1 
megawatt (MW). Regulated categories and entities include:

[[Page 8316]]



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                  Category                        NAICS            SIC          Examples of regulated entities
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Any industry using a new stationary                    2211            4911  Electric services.
 combustion turbine as defined in the
 proposed 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.
----------------------------------------------------------------------------------------------------------------

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be regulated by this 
action. To determine whether your facility is regulated by this action, 
you should examine the applicability criteria in section 60.4305 of the 
proposed rule. For further information concerning applicability and 
rule determinations, contact the appropriate State or local agency 
representative. For information concerning the analyses performed in 
developing the New Source Performance Standards (NSPS), consult the 
contact person listed in the preceding FOR FURTHER INFORMATION CONTACT 
section.

B. What Should I Consider as I Prepare My Comments for EPA?

    1. Submitting CBI. Do not submit this information to EPA through 
EDOCKET, regulations.gov or e-mail. Send or deliver information 
identified as CBI to only the following address: Mr. Jaime Pagan, c/o 
OAQPS Document Control Officer (Room C404-02), U.S. EPA, Research 
Triangle Park, NC 27711, Attention Docket ID No. OAR-2004-0490. Clearly 
mark the part or all of the information that you claim to be CBI. For 
CBI information in a disk or CD ROM that you mail to EPA, mark the 
outside of the disk or CD ROM as CBI and then identify electronically 
within the disk or CD ROM the specific information that is claimed as 
CBI. In addition to one complete version of the comment that includes 
information claimed as CBI, a copy of the comment that does not contain 
the information claimed as CBI must be submitted for inclusion in the 
public docket. Information so marked will not be disclosed except in 
accordance with procedures set forth in 40 CFR part 2.
    2. Tips for Preparing Your Comments. When submitting comments, 
remember to:
    a. Identify the rulemaking by docket number and other identifying 
information (subject heading, Federal Register date and page number).
    b. Follow directions. The EPA may ask you to respond to specific 
questions or organize comments by referencing a Code of Federal 
Regulations (CFR) part or section number.
    c. Explain why you agree or disagree; suggest alternatives and 
substitute language for your requested changes.
    d. Describe any assumptions and provide any technical information 
and/or data that you used.
    e. If you estimate potential costs or burdens, explain how you 
arrived at your estimate in sufficient detail to allow for it to be 
reproduced.
    f. Provide specific examples to illustrate your concerns, and 
suggest alternatives.
    g. Explain your views as clearly as possible, avoiding the use of 
profanity or personal threats.
    h. Make sure to submit your comments by the comment period deadline 
identified.
    Docket. The docket number for the proposed NSPS (40 CFR part 60, 
subpart KKKK) is Docket ID No. OAR-2004-0490.
    World Wide Web (WWW). In addition to being available in the docket, 
an electronic copy of the proposed rule is also available on the WWW 
through the Technology Transfer Network Website (TTN Web). Following 
signature, EPA will post a copy of the proposed rule on the TTN's 
policy and guidance page for newly proposed or promulgated rules at 
https://www.epa.gov/ttn/oarpg. The TTN provides information and 
technology exchange in various areas of air pollution control. If you 
need more information regarding the TTN, call the TTN HELP line at 
(919) 541-5384.

II. Background Information

    This action proposes NSPS that would apply to new stationary 
combustion turbines greater than or equal to 1 MW that commence 
construction, modification or reconstruction after February 18, 2005. 
The NSPS are being proposed pursuant to section 111 of the Clean Air 
Act (CAA) which requires the EPA to promulgate and periodically revise 
the NSPS, taking into consideration available control technologies and 
the costs of control. The EPA promulgated the 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 turbines have occurred. Nitrogen oxides and 
SO2 are known to cause adverse health and environmental 
effects. The proposed standards represent reductions in the 
NOX and SO2 limits of over 80 and 93 percent, 
respectively. The output-based standards in the proposed rule would 
allow owners and operators the flexibility to meet their emission limit 
targets by increasing the efficiency of their turbines.

III. Summary of the Proposed Rule

A. Does the Proposed Rule Apply to Me?

    Today's proposed standards would apply to new stationary combustion 
turbines with a power output at peak load greater than or equal to 1 
MW. The applicability of the proposed rule is similar to that of 
existing 40 CFR part 60, subpart GG, except that the proposed rule 
would apply to new stationary combustion turbines, and their associated 
heat recovery steam generators (HRSG) and duct burners. A new 
stationary combustion turbine is defined as any simple cycle combustion 
turbine, regenerative cycle combustion turbine, or combined cycle 
steam/electric generating system that is not self-propelled and that 
commences construction, modification, or reconstruction after February 
18, 2005. The new stationary combustion turbines subject to the 
proposed standards are exempt from the requirements of 40 CFR part 60, 
subpart GG. Heat recovery steam generators and duct burners subject to 
the proposed rule would be exempt from the requirements of 40 CFR part 
60, subparts Da and Db.

B. What Pollutants Would Be Regulated?

    The pollutants to be regulated by the proposed standards are 
NOX and SO2.

C. What Is the Affected Source?

    The affected source for the proposed stationary combustion turbine 
NSPS is each stationary combustion turbine with a power output at peak 
load greater than or equal to 1 MW, 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 NSPS) are exempt 
from the requirements of the proposed rule.

[[Page 8317]]

D. What Emission Limits Must I Meet?

    The format of the proposed standards for NOX is an 
output-based emission limit in units of emissions mass per unit useful 
recovered energy, nanograms/Joule (ng/J) or pounds per megawatt-hour 
(lb/MW-hr). There are four subcategories, and thus four separate 
output-based NOX limits. These are presented in Table 1 of 
this preamble. The output of the turbine does not include any steam 
turbine output and refers to the rating of the combustion turbine 
itself.

                                     Table 1.--NOX Emission Standards (ng/J)
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                                                                 Combustion turbine size
     Combustion turbine fuel type      -------------------------------------------------------------------------
                                                      < 30 MW                              >= 30 MW
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Natural gas...........................  132 (1.0 lb/MW-hr)                   50 (0.39 lb/MW-hr)
Oil and other fuel....................  234 (1.9 lb/MW-hr)                   146 (1.2 lb/MW-hr)
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    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. In 
addition, we are proposing that combustion turbines used by 
manufacturers in research and development of equipment for both 
combustion turbine emission control techniques and combustion turbine 
efficiency improvements be exempted from the NOX limit. 
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 case by case basis only.
    The proposed 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 73 ng/J 
(0.58 lb/MW-hr). You would be able to choose to comply with the 
SO2 limit itself or with a limit on the sulfur content of 
the fuel. We are proposing this sulfur content limit to be 0.05 percent 
by weight (500 parts per million by weight (ppmw)).

E. If I Modify or Reconstruct My Existing Turbine, Does the Proposed 
Rule Apply to Me?

    The proposed standards would apply to stationary combustion 
turbines that are modified or reconstructed after February 18, 2005. 
The guidelines for determining whether a source is modified or 
reconstructed are given in 40 CFR 60.14 and 60.15, respectively.

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 would 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, between 90 and 100 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. The 
requirement to test at three additional load levels is waived.

G. What Monitoring Requirements Must I Meet?

    If you are using water or steam injection to control NOX 
emissions, you would have to install and operate a continuous 
monitoring system to monitor and record the fuel consumption and the 
ratio of water or steam to fuel being fired in the turbine. 
Alternatively, you could use a CEMS consisting of NOX and 
oxygen (O2) or carbon dioxide (CO2) monitors. 
During each full unit operating hour, each monitor would 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 
would 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 would have to 
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 would define at least four 
parameters indicative of the unit's NOX formation 
characteristics, and you would monitor these parameters continuously;
    (2) For any lean premix stationary combustion turbine, you would 
continuously monitor the appropriate parameters to determine whether 
the unit is operating in the lean premixed combustion mode;
    (3) For any turbine that uses SCR to reduce NOX 
emissions, you would 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, if you elect to 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 could petition the Administrator for other 
acceptable methods of monitoring your emissions. If you choose to use a 
CEMS or perform parameter monitoring to demonstrate

[[Page 8318]]

continuous compliance, annual stack testing is not required.
    If you operate any stationary combustion turbine subject to the 
provisions of the proposed rule, and you choose not to comply with the 
SO2 stack limit, you would 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; and the sulfur content would 
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 sulfur content of the fuel 
combusted in the turbine, if you demonstrate that the fuel does not to 
exceed a total sulfur content of 300 ppmw. 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 sulfur content of 
the fuel does not exceed 300 ppmw.
    If you choose to monitor combustion parameters or parameters 
indicative of proper operation of NOX emission controls, the 
appropriate parameters would 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.
    If you are required to periodically determine the sulfur content of 
the fuel combusted in the turbine, a minimum of three fuel samples 
would be collected during the performance test. For liquid fuels, the 
samples for the total sulfur content of the fuel must be analyzed using 
American Society of Testing and Materials (ASTM) methods D129-00, 
D2622-98, D4294-02, D1266-98, D5453-00 or D1552-01. For gaseous fuels, 
ASTM D1072-90 (Reapproved 1999); D3246-96; D4468-85 (Reapproved 2000); 
or D6667-01 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 proposed rule, you would submit reports of excess 
emissions and monitor downtime, in accordance with 40 CFR 60.7(c). 
Excess emissions would 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.

IV. Rationale for the Proposed Rule

A. Why Did EPA Choose Output-Based Standards?

    We have written the proposed standards to incorporate output-based 
NOX and SO2 limits. The primary benefit of 
output-based standards is that they recognize energy efficiency as a 
form of pollution prevention. The use of more efficient technologies 
reduces fossil fuel use and leads to reductions in the environmental 
impacts associated with the production and use of fossil fuels. Another 
benefit is that output-based standards allow sources to use energy 
efficiency as a part of their emissions control strategy. This provides 
an additional compliance option that can lead to reduced compliance 
costs as well as lower emissions.
    Several States have initiated regulations or permits-by-rule for 
distributed generation (DG) units, including combustion turbines. 
States that have made efforts to regulate DG sources include 
California, Texas, New York, New Jersey, Connecticut, Delaware, Maine, 
and Massachusetts. Those State rules include emission limits that are 
output-based, and many allow generators that use combined heat and 
power (CHP) to take credit for heat recovered. For example, Texas 
recently passed a DG permit-by-rule regulation that gives facilities 
100 percent credit for steam generation thermal output, and 
incorporates HRSG and duct burners under the same limit. The California 
Air Resources Board (CARB) also has output-based emission limits which 
allow DG units that use CHP to take a credit to meet the standards, at 
a rate of 1 MW-hr for each 3.4 million British thermal units (MMBtu) of 
heat recovered, or essentially, 100 percent. The draft rules for New 
York and Delaware also allow DG sources using CHP to receive credit 
toward compliance with the emission standards.

B. How Did EPA Determine the Proposed NOX Limits?

    Over the last several years NOX performance in 
combustion turbines has improved dramatically. At the current time, 
lean premix turbines, or dry low NOX, dominate the market 
for combustion turbines fired by natural gas. To determine the proposed 
NOX limits, we evaluated stack test data for stationary 
combustion turbines of different sizes. The data provided us with 
information on actual NOX emissions performance in relation 
to the size of the unit and the type of fuel being used. In addition, 
we obtained information from turbine manufacturers on the 
NOX levels that they guarantee for their new stationary 
combustion turbines. We only used these manufacturer guarantees to 
confirm the NOX levels observed in the stack test data that 
we studied.
    We considered requiring the use of SCR in setting the limit for 
NOX. However, we determined that the costs for SCR were high 
compared to the incremental difference in emission concentration. Newer 
large turbines without add-on controls can readily achieve 9 or 10 
parts per million (ppm). The use of SCR might bring this level down to 
2 to 4 ppm. In addition, SCR may be difficult to implement for turbines 
operating under variable loads. We determined that the incremental 
benefit in emissions reductions did not justify the costs and technical 
challenges associated with the addition and operation of SCR. 
Therefore, we did not base the NOX emission limit on this 
add-on control. However, add-on control technologies may be required at 
the State or local level, for Prevention of Significant Deterioration 
(PSD) and New Source Review (NSR) programs.
    We identified a distinct difference in the technologies and 
capabilities between small and large turbines. We found the breaking 
point between these two turbine types to be 30 MW. Smaller turbines 
have less space to install NOX reducing technologies such as 
lean premix combustor design. In addition, the smaller combustion 
chamber of small turbines provides inadequate space for the adequate 
mixing needed for very low NOX emission levels. The design 
differences between small and large turbines leads to different 
emission characteristics. When we examined data of NOX 
emissions versus turbine size, there was a clear difference in 
NOX emissions for turbines below and above 30 MW. In 
addition, manufacturer guarantees are, generally speaking, higher for 
smaller turbines, because of differences in design and technologies. 
The 30 MW cutoff is consistent with the manufacturer guarantees.
    As explained below, the output-based NOX limits being 
proposed are based on

[[Page 8319]]

concentration levels that are achievable by new stationary combustion 
turbines without the use of add-on controls such as SCR. Also, it is 
important to note that the output-based limits were determined using 
thermal efficiencies typical of full-load operation.
Small Natural Gas Fired Turbines
    We are proposing the NOX limit for small (less than 30 
MW) natural gas-fired turbines to be 132 ng/J, or 1.0 lb/MW-hr. This 
limit is based on a NOX emission concentration of 25 ppm and 
a turbine efficiency of 30 percent. Multiple manufacturers guarantee 25 
ppm NOX for natural gas-fired turbines of all sizes, 
including those less than 30 MW. Since actual NOX emissions 
are considerably lower than the guaranteed levels for most turbines, an 
emission limit based on a NOX level of 25 ppm at 15 percent 
O2 for small natural gas-fired turbines can readily be 
achieved without the use of additional controls. We also gathered many 
recent source tests, supporting the conclusion that the majority of new 
small natural gas-fired turbines can achieve NOX levels 
lower than 25 ppm at 15 percent O2 without the use of add-on 
controls. Regarding efficiency, a significant number of small turbines 
are simple cycle; therefore, we selected the baseline efficiency of 30 
percent for small simple cycle natural gas-fired turbines.
Large Natural Gas Fired Turbines
    We are proposing a NOX emission limit of 50 ng/J (0.39 
lb/MW-hr) for large natural gas-fired turbines (greater than or equal 
to 30 MW). The proposed NOX output-based limit for large 
natural gas-fired turbines is based on a NOX emission 
concentration of 15 ppm at 15 percent O2 and a combined 
cycle turbine efficiency of 48 percent, which also equates to a 
NOX emission concentration of 9 ppm at 15 percent 
O2 and a simple cycle turbine at an efficiency of 29 
percent. Many manufacturers guarantee NOX emissions of 15 
ppm at 15 percent O2 for large natural gas-fired turbines, 
and a few even guarantee NOX levels at or below 9 ppm at 15 
percent O2. In addition, we have gathered a number of source 
tests which confirm that these turbines can achieve these levels 
without the use of add-on controls. Therefore, this emission limit may 
be achieved by most large natural gas combustion turbines without the 
use of add-on controls. Other options for new turbine owners and 
operators include the following: Add a SCR add-on control device to a 
simple cycle turbine which does not have a low NOX 
guarantee, or locate their turbine where the exhaust heat can be 
recovered as useful output (a combined cycle unit or CHP unit).
Distillate Oil Fired Turbines
    Very few turbines sold today are solely distillate oil-fired. 
However, a significant number of turbines which primarily fire natural 
gas also have the capability to fire distillate oil. We are proposing a 
NOX emission limit of 234 ng/J (1.9 lb/MW-hr) for small 
distillate oil-fired turbines, and 146 ng/J (1.2 lb/MW-hr) for large 
distillate oil-fired turbines. When firing distillate oil fuel, the 
majority of turbine manufacturers guarantee a NOX emission 
level of 42 ppm at 15 percent O2, regardless of turbine 
size. We confirmed through the analysis of recent source test reports 
provided by States that this level is achievable by the majority of new 
distillate oil-fired turbines without the use of add-on controls. The 
basis for the output-based emission limits for distillate oil-fired 
turbines is 42 ppm NOX at 15 percent O2; for 
small turbines, a 30 percent efficiency, and for large turbines, a 48 
percent efficiency. The 30 percent efficiency for small oil-fired 
turbines is consistent with that of simple-cycle units, while the 48 
percent efficiency for large oil-fired turbines is consistent with that 
of combined-cycle units. This approach is appropriate since there are 
almost no oil-fired simple-cycle turbines in the ``greater than 30 MW'' 
category. We would like to request comment on this issue and the 
appropriateness of the NOX limits for oil-fired simple-cycle 
turbines that are greater than 30 MW. Furthermore, since according to 
our information, most of these simple-cycle turbines are used as 
peaking units, we would like to request comments on an alternative 
approach that allows large oil-fired peaking units to meet the same 
NOX limit that applies to the small units.
    The proposed output-based NOX limits for oil-fired 
combustion turbines can be achieved when operating at loads near 100 
percent, where the thermal efficiency tends to be the highest. However, 
at part-loads, there may be concern about higher output-based 
NOX levels emitted due to the lower thermal efficiencies 
that are characteristic under those conditions. We request comment on 
the ability of oil-fired combustion turbines to meet the proposed 
NOX limits under part-load operation.
Other Fuels
    It is expected that few turbines would burn fuels other than 
natural gas and distillate oil. Turbines that burn other fuels would 
have to comply with the NOX emission limit for distillate 
oil. We understand that there are concerns about certain fuels, such as 
landfill, digester and other waste gases, process, refinery or syn 
gases, and other alternative fuels. Of particular concern are the fuels 
that are of lower heating value or of highly variable heating value, 
that are in locations where these fuels would be flared or otherwise 
disposed without energy recovery. Landfill and digester gases have 
considerably lower heating values than natural gas, making it more 
difficult to comply with an output-based emission limit. If the 
installation of these turbines became impossible due to lack of ability 
to comply with the NSPS, these gases might otherwise just be vented to 
the atmosphere or flared, without the benefit of any useful energy 
recovery as would have been achieved with a combustion turbine. Because 
of these issues, we are requesting public comment on the output-based 
NOX limit for alternative fuels.
Simple-Cycle and Combined-Cycle Combustion Turbines
    Although we believe that proposing different NOX limits 
for small and large turbines is appropriate, an alternative approach 
considered was to set different NOX limits for simple-cycle 
and combined-cycle combustion turbines burning natural gas. Simple-
cycle turbines are not able to recover exhaust heat as combined-cycle 
turbines do. As a result, the output-based NOX levels of 
simple-cycle turbines will tend to be higher than those for combined-
cycle units. Even though we have taken into account these differences 
between simple- and combined-cycle turbines in the proposed 
NOX limits, we would like to request comment on this issue. 
If data is presented showing that it would be more appropriate to set 
different NOX limits for simple-cycle and combined-cycle 
gas-fired turbines, rather than based on turbine size, we would 
consider a range of 0.2 lb/MW-hr to 0.6 lb/MW-hr.
    Supporting data for the proposed NOX limits were 
received from contacts with turbine manufacturers, State agencies and 
EPA Regional offices, the 2003 Gas Turbine World Handbook, the 2003-
2004 Diesel and Gas Turbine Worldwide Catalog, NOX 
performance tests, and State permit data. For more details regarding 
the supporting data used in this analysis, please consult the docket.

C. How Did EPA Determine the Proposed SO2 Limit?

    Because of the lower levels of sulfur in today's fuels, including 
distillate oil and natural gas, lower SO2 emissions can be 
achieved. Low sulfur fuel oil (500 ppmw sulfur content or less) has

[[Page 8320]]

recently become widely available, since it is required by EPA 
regulations on diesel fuels used for highway and non-road applications. 
In addition, ultra low sulfur (15 ppmw or less sulfur content) diesel 
fuel will become available over the next few years as more recent EPA 
rules for fuels used on highway and non-road applications come into 
effect. According to EPA estimates done for the Non-Road Diesel Rule 
(69 FR 38958), the cost differential to produce low sulfur (500 ppmw 
sulfur content) is only about 2.5 cents per gallon. It is expected that 
stationary combustion turbines burning low sulfur diesel fuel will have 
lower maintenance expenses associated with reduced formation of acid 
compounds inside the turbine. These lower maintenance expenses are 
expected to reduce or even eliminate the overall costs associated with 
the use of low sulfur fuel oil on stationary combustion turbines. For 
these reasons, we have set a SO2 emission limit which 
corresponds to a 500 ppmw sulfur fuel content for distillate oil fuel. 
Natural gas also has naturally low levels of sulfur.
    All owners and operators of new turbines are expected to comply 
with low sulfur content in fuel rather than stack testing for 
SO2, since this option is significantly easier and less 
costly to perform than stack testing. In addition, if the levels are 
shown to be below 300 ppmw sulfur, fuel monitoring is not required. 
Fuels are often supplied with specifications which include stringent 
sulfur standards, requiring levels lower than 500 ppmw, oftentimes at 
or below the 300 ppmw range. If the fuel is demonstrated to be lower 
than 300 ppmw sulfur, you could use proof from the fuel vendor's tariff 
sheet or purchase contract in order to become exempt from monitoring 
your total sulfur content or SO2 emissions. We believe that 
300 ppmw provides an adequate margin of compliance. If your fuel is 
greater than 300 ppmw, you must follow a fuel monitoring schedule as 
outlined in the proposed rule.

D. What Other Criteria Pollutants Did EPA Consider?

    In order to characterize the current emissions levels from new 
stationary combustion turbines, the Reasonably Achievable Control 
Technology (RACT), Best Available Control Technology (BACT) and Lowest 
Achievable Emissions Rate (LAER) Clearinghouse (RBLC) was queried to 
obtain data on permits for newly installed turbines. The EPA's AP-42 
Emission Factors Background Document was also consulted for information 
on pollutant formation mechanisms. In addition, several turbine 
manufacturers were contacted to determine their guaranteed emission 
concentrations.
    Emissions from combustion turbines are primarily NOX and 
carbon monoxide (CO). Particulate matter (PM) is also a primary 
pollutant for combustion turbines using liquid fuels. While 
NOX formation is strongly dependent on the high temperatures 
developed in the combustor, emissions of CO and PM are primarily the 
result of incomplete combustion. Ash and metallic additives in the fuel 
may also contribute to PM in the exhaust. Available emissions data in 
EPA's AP-42 indicate that the turbine's operating load has a 
considerable effect on the resulting emission levels. Combustion 
turbines are typically operated at high loads (greater than or equal to 
80 percent of rated capacity) to achieve maximum thermal efficiency and 
peak combustor zone flame temperatures. Information on each pollutant 
is listed below, including formation, control, and emission 
concentrations.
Carbon Monoxide
    Carbon monoxide is a product of incomplete combustion. Carbon 
monoxide results when there is insufficient residence time at high 
temperature, or incomplete mixing to complete the final step in fuel 
carbon oxidation. The oxidation of CO to CO2 at combustion 
turbine temperatures is a slow reaction compared to most hydrocarbon 
oxidation reactions. In combustion turbines, failure to achieve CO 
burnout may result from quenching by dilution air. With liquid fuels, 
this can be aggravated by carryover of larger droplets from the 
atomizer at the fuel injector. Carbon monoxide emissions are also 
dependent on the loading of the combustion turbine. For example, a 
combustion turbine operating under full load would experience greater 
fuel efficiencies, which will reduce the formation of CO.
    Turbine manufacturers have significantly reduced CO emissions from 
combustion turbines by developing lean premix technology. Most of the 
newer designs for turbines incorporate lean premix technology. Lean 
premix combustion design not only produces lower NOX than 
diffusion flame technology, but also lowers CO and volatile organic 
compounds (VOC), due to increased combustion efficiency. In the most 
recent version of AP-42 emission factors, (April 2000), CO emission 
factors for lean premix turbines are 9.9 e-2 lb/MMBtu, while for 
diffusion flame turbines, the CO emission factor is 3.2 e-1 lb/MMBtu. 
Virtually all new combustion turbines sold are lean premix combustor 
technology turbines. Siemens Westinghouse, Solar Turbines, and General 
Electric (GE) Heavy Duty Turbine manufacturers typically guarantee CO 
emissions from 9 to 50 ppm for natural gas, and 20 to 50 ppm for diesel 
fuel. On a case-by-case basis, some manufacturers will guarantee lower 
emissions for CO.
    Stationary combustion turbines do not contribute significantly to 
ambient CO levels. Almost 80 percent of CO emissions nationwide result 
from on-road vehicles and non-road vehicles and engines. High levels of 
CO generally occur in areas that have heavy traffic congestion. 
Currently, there are only eight areas in the U.S. that are classified 
as non-attainment for CO. As a result, control measures for CO 
emissions from stationary combustion turbines historically have not 
been instituted nationwide. In California, for example, only one air 
district has a CO emission limit for combustion turbines. Because of 
advances in turbine technology and increases in thermal and combustion 
efficiencies, CO emissions from combustion turbines have been mostly 
regulated in local areas of non-attainment for CO.
    Any new major stationary source or major modification located in an 
area attaining the National Ambient Air Quality Standard (NAAQS) is 
subject to PSD requirements and must conduct an analysis to ensure the 
application of BACT. Similarly, if the source is in a non-attainment 
area, it is subject to non-attainment NSR and must conduct an analysis 
to ensure the application of LAER. The RBLC provides State agencies 
with the best technologies and emission rates determined by other 
States on a nationwide basis. Several BACT and LAER determinations in 
the RBLC included the use of an oxidation catalyst to control CO 
emissions from stationary combustion turbines. Out of the 42 permits 
for CO for combustion turbines reported since January 2003, 15 required 
the use of oxidation catalysts for CO reduction. Other requirements 
included good combustion practices and good combustion design. Emission 
limitations ranged from 2 ppm to 14 ppm for CO with the use of 
oxidation catalysts, and 4 ppm to 132 ppm CO for good combustion 
practices and design.
    Based on the available information, we propose that no CO emission 
limitations be developed for the combustion turbine NSPS. With the 
advancement of turbine technology and more complete combustion through 
increased efficiencies, and the prevalence of lean premix combustion 
technology in new turbines, it is not necessary to further reduce CO in 
the

[[Page 8321]]

proposed rule. Because of these advances, the addition of an oxidation 
catalyst would be cost prohibitive, on a dollar per ton basis, relative 
to the limited additional emissions reductions to be realized. However, 
individual States may continue to evaluate CO limits on a case-by-case 
basis, as has been done historically and as has been required in the 
NSR Program.
Volatile Organic Compounds
    Volatile organic compounds are also products of incomplete 
combustion. These compounds are discharged into the atmosphere when 
fuel remains unburned or is burned only partially during the combustion 
process. The pollutants commonly classified as VOC can encompass a wide 
spectrum of organic compounds, some of which are hazardous air 
pollutants. With natural gas, some organics are carried over as 
unreacted, trace constituents of the gas, while others may be pyrolysis 
products of the heavier hydrocarbon constituents. With liquid fuels, 
large droplet carryover to the quench zone accounts for much of the 
unreacted and partially pyrolized volatile organic emissions. Similar 
to CO emissions, VOC emissions are affected by the gas turbine 
operating load conditions. Volatile organic compounds emissions are 
higher for gas turbines operating at low loads as compared to similar 
gas turbines operating at higher loads.
    Owners of combustion turbines have improved combustion practices to 
increase combustion efficiency in the turbine, thereby limiting the 
unburned fuel. In addition, lean premix technology has significantly 
reduced VOC emissions from combustion turbines by increasing the 
combustion efficiency. Because of better combustion practices, and the 
prevalence of lean premix combustion technology in new turbines, it is 
not necessary to regulate VOC in the proposed rule. Therefore, we 
propose that no VOC emission limitations be developed for the 
combustion turbine NSPS.
Particulate Matter
    Particulate matter emissions from turbines result primarily from 
carryover of noncombustible trace constituents in the fuel. Particulate 
matter emissions are negligible with natural gas firing due to the low 
sulfur content of natural gas. Emissions of PM are only marginally 
significant with distillate oil firing because of the low ash content. 
The sulfur content of distillate fuel is decreasing due to requirements 
from other regulations such as the non-road diesel engine rule. 
Particulate matter emissions from distillate oil-fired turbines would 
decrease even further as the sulfur content of distillate oil 
decreases. Furthermore, there are very few new turbines that solely 
fire distillate oil. A fraction have the ability to fire distillate oil 
(dual-fuel units), but generally speaking, most owners and operators 
fire natural gas the majority of the time.
    A review of the BACT and LAER determinations in the RBLC since 
January of 2003 showed that no add-on controls were required to limit 
PM for any of the turbines. Permit requirements included the use of 
clean fuel or good combustion practices. Emission limitations required 
by permits in the RBLC database with permit dates after January of 2003 
ranged from 9 pounds per hour (lb/hr) to 27 lb/hr for PM for natural 
gas, and 27 to 44 lb/hr for PM for diesel-fired turbines. General 
Electric is the only manufacturer who provides PM guarantees on their 
heavy duty turbines, and these guarantees ranged from 3 lb/hr to 15 lb/
hr for natural gas, and 6 lb/hr to 34 lb/hr for diesel fuel.
    As fuels continue to get cleaner, PM would be greatly reduced. In 
addition, the NOX limits set forth in the proposed rule 
would also limit PM emissions by reducing nitrate formation. Therefore, 
we feel that an emission limitation for PM emissions from stationary 
combustion turbines is not necessary.

E. How Did EPA Determine Testing and Monitoring Requirements for the 
Proposed Rule?

    Monitoring provisions in subpart GG of 40 CFR part 60 only 
addressed turbines that used water injection for NOX 
control. Over the years, EPA has approved on a case-by-case basis 
alternative monitoring methods for turbines that do not use water 
injection for NOX control, since this technology has become 
increasingly archaic. Some requested the use of a NOX CEMS, 
since the turbines had these monitoring systems already in place for 
other regulatory requirements, such as the acid rain regulations or 
PSD/NSR permits. In the July 8, 2004 amendments to subpart GG of 40 CFR 
part 60, Stationary Gas Turbine NSPS (69 FR 41346), we added the option 
to utilize a NOX CEMS in place of water to fuel ratio 
monitoring. We also included in the July 8, 2004 final rule a provision 
allowing sources to use CEMS to monitor their NOX emissions 
for turbines that do not use water or steam injection.
    In today's action, we are proposing monitoring requirements similar 
to those in 40 CFR part 60, subpart GG. For turbines that do not use 
water or steam injection, we are proposing annual stack testing to 
demonstrate continuous compliance. We considered other monitoring 
requirements, including CEMS and parametric monitoring. However, costs 
were high compared to costs for annual stack testing and annual stack 
testing provides a reliable means of demonstrating compliance. 
Therefore, annual stack testing is an appropriate monitoring method, 
and would help ensure continuous compliance with the new NOX 
limits.
    We also considered the use of portable analyzers as monitoring 
requirements. Recent testing by EPA has shown portable analyzers to be 
a reliable method of monitoring emissions, and they are believed to be 
as good as the traditional EPA method tests. Costs are comparable to 
EPA method tests. Portable analyzers are, therefore, a viable option to 
traditional method stack tests and the proposed rule allows the use of 
ASTM D6522-00 to measure the NOX concentration during 
performance testing.
    Many of the large turbines in the utility sector are already 
equipped with NOX CEMS for compliance with other 
regulations, such as 40 CFR part 75. It is appropriate to allow the use 
of NOX CEMS to demonstrate compliance with the proposed 
rule, particularly when they are already installed on-site for other 
regulatory purposes. Continuous emission monitoring systems are, 
therefore, the natural choice for these large turbines, and we are 
allowing the use of data from these certified CEMS for demonstrating 
compliance instead of an annual stack test.
    Also, we included additional options for owners and operators to 
establish parameters which would be appropriate to monitor in order to 
correlate NOX emissions with these data. Historically, some 
turbines have used parametric monitoring for compliance with 40 CFR 
part 75 requirements. For example, the owner/operator of a lean premix 
turbine might establish during the initial performance test that when 
the turbine is running in the lean premix mode, it is in compliance. 
Certain parameters, such as load or combustion temperature, might let 
the owner or operator know when the turbine is in compliance. Another 
option is for owners or operators to petition the Administrator for 
approval of another monitoring strategy.

F. Why Are Heat Recovery Steam Generators Included in 40 CFR Part 60, 
Subpart KKKK?

    For sources that are combined cycle turbine systems using 
supplemental heat, turbine NOX emissions would be

[[Page 8322]]

measured after the duct burner, since emissions and output associated 
with duct burners are included in the NOX emission limit. 
Any combined cycle units that are subject to the NOX CEMS 
requirements for 40 CFR part 75 would most likely have installed the 
CEMS after the duct burner, on the HRSG stack. Another reason to 
require measurement of NOX emissions after the duct burner 
is that add-on NOX control systems, such as SCR, are 
generally located after the duct burner. Turbine NOX 
performance testing should be conducted after the NOX 
control device and would, therefore, include any emissions from the 
duct burner.
    In addition, all of the data that we have gathered where emissions 
were tested with and without duct burner firing show that duct burners 
have little to no effect on NOX emissions. Minimal additions 
and reductions were noted in several recent source tests, as well as an 
EPA sponsored test conducted by the EPA's Emissions Measurement Center. 
Thus, it is appropriate to include heat recovery sources such as duct 
burners in the proposed rule.

G. What Emission Limits Must I Meet if I Fire More Than One Type of 
Fuel?

    New combustion turbines that fire both natural gas and distillate 
oil (or some other combination of fuels) are required to meet the 
corresponding emission limit for the fuel being fired in the turbine at 
that time.

H. Why Can I No Longer Claim a Fuel-Bound Nitrogen Allowance?

    We are not including a fuel-bound nitrogen allowance in the 
proposed rule. In subpart GG of 40 CFR part 60, this provision allowed 
sources to claim a credit for nitrogen content in their fuel, up to a 
certain limit, attributing a part of their NOX emissions to 
the fuel. We concluded that this provision is outdated since the 
nitrogen content of fuel is now lower than it has been in the past and 
is no longer an issue. The vast majority of new turbines are fired by 
natural gas. Many of these turbines are permitted to fire only pipeline 
quality natural gas, which is virtually nitrogen free. We do not 
anticipate any new turbines needing to utilize the fuel-bound nitrogen 
allowance, and are, therefore, not proposing it.

I. Why Isn't My IGCC Turbine Covered in 40 CFR Part 60, Subpart KKKK?

    We consider gasification as an emissions control technology for 
solid fuels. Therefore, we consider it appropriate to cover combustion 
turbines fueled by gasified coal under the Utility NSPS. Combustion 
turbines fueled by gasified coal and not meeting the heat input 
requirements of the Utility NSPS would be covered by the proposed rule 
under the ``other fuel'' category.

V. Environmental and Economic Impacts

    In setting the standards, the CAA requires us to consider 
alternative emission control approaches, taking into account the 
estimated costs and benefits, as well as the energy, solid waste and 
other effects. The EPA requests comment on whether it has identified 
the appropriate alternatives and whether the proposed standards 
adequately take into consideration the incremental effects in terms of 
emission reductions, energy and other effects of these alternatives. 
The EPA will consider the available information in developing the final 
rule.

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 rule, as proposed. No more than ten of these units 
may need to install add-on controls to meet the NOX limits 
required under the rule, as proposed. However, these ten new turbines 
will already be required to install add-on controls to meet 
NOX reduction requirements under PSD/NSR. Thus, we concluded 
that the NOX and CO reductions resulting from the rule, as 
proposed, will essentially be zero. The expected SO2 
reductions as a result of the rule, as proposed, would be approximately 
830 tons per year (tpy) in the 5th year after promulgation of the 
standards.
    Although we expect the proposed rule to result in a slight increase 
in electrical supply generated by unaffected sources (e.g. existing 
stationary combustion turbines), we do not believe that this will 
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 proposed rule.

B. What Are the Energy Impacts?

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

C. What Are the Economic Impacts?

    The EPA prepared an economic impact analysis to evaluate the 
impacts the proposed 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 proposed 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 rule, as proposed, 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 proposed 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 
proposed 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

[[Page 8323]]

determine whether a regulatory action is ``significant'' and, 
therefore, subject to review by 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. The EPA submitted this action to 
OMB for review. Changes made in response to OMB suggestions or 
recommendations would be documented in the public record.

B. Paperwork Reduction Act

    The information collection requirements in the proposed rule have 
been submitted for approval to OMB under the Paperwork Reduction Act, 
44 U.S.C. 3501 et seq. The Information Collection Request (ICR) 
document prepared by EPA has been assigned ICR No. 2177.01.
    The proposed 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 proposed rule would 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 [date the final rule 
is published in the Federal Register]) 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; develo