FR Doc 03-8150

[Federal Register: April 14, 2003 (Volume 68, Number 71)]
[Rules and Regulations]
[Page 17989-18002]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr14ap03-7]

[[Page 17989]]

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Part II

Environmental Protection Agency

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40 CFR Part 60

Standards of Performance for Stationary Gas Turbines; Direct Final Rule
and Proposed Rule

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[OAR-2002-0053, FRL-7476-5]
RIN 2060-AK35

Standards of Performance for Stationary Gas Turbines

AGENCY: Environmental Protection Agency (EPA).

ACTION: Direct final rule; amendments.

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SUMMARY: This action promulgates amendments to several sections of the
standards of performance for stationary gas turbines. The amendments
will codify several alternative testing and monitoring procedures that
have routinely been approved by EPA. The amendments will also reflect
changes in nitrogen oxides (NOX) emission control
technologies and turbine design since the standards were originally
promulgated.

DATES: The direct final rule will be effective May 29, 2003, unless we
receive adverse comments by May 14, 2003. If such comments are
received, then EPA will publish a timely withdrawal in the Federal
Register indicating which provisions will become effective and which
provisions are being withdrawn due to adverse comment. Any distinct
amendment, paragraph or section of the direct final rule for which we
do not receive adverse comment will become effective on the date set
above, notwithstanding any adverse comment on any other distinct
amendment, paragraph, or section of the direct final rule. The
incorporation by reference of certain publications in the direct final
rule is approved by the Director of the Office of the Federal Register
as of May 29, 2003.

ADDRESSES: Comments. By U.S. Postal Service, send comments (in
duplicate, if possible) to: EPA Docket Center (6102T), Attention Docket
Number OAR-2002-0053, U.S. EPA, 1200 Pennsylvania Avenue, NW.,
Washington, DC 20460. In person or by courier, deliver comments (in
duplicate, if possible) to: Air and Radiation Docket, Attention Docket
Number OAR-2002-0053, U.S. EPA, 1301 Constitution Avenue, NW., Room B-
108, Washington, DC 20460. We request that a separate copy also be sent
to the contact person listed below (see FOR FURTHER INFORMATION
CONTACT).

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; electronic mail address pagan.jaime@epa.gov.
SUPPLEMENTARY INFORMATION: Regulated Entities. Entities potentially
regulated by this action are those that own and operate stationary gas
turbines, and are the same as the existing rule in 40 CFR part 60,
subpart GG. Regulated categories and entities include:

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Category NAICS SIC Examples of regulated entities
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Any industry using a stationary combustion 2211 4911 Electric services.
turbine as defined in the direct 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.
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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 Sec. 60.330 of the
final rule. If you have questions regarding the applicability of this
action to a particular entity, consult the contact person listed in the
preceding FOR FURTHER INFORMATION CONTACT section.
Docket. EPA has established an official public docket for this
action under Docket ID No. OAR-2002-0053. The official public docket
consists of the documents specifically referenced in this action, any
public comments received, and other information related to this action.
Although a part of the official docket, the public docket does not
include Confidential Business Information (CBI) or other information
whose disclosure is restricted by statute. The official public docket
is the collection of materials that is available for public viewing at
the Air Docket in the EPA Docket Center, Room B108, 1301 Constitution
Ave., NW., Washington, DC 20460. The EPA Docket Center 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. The telephone number for the Air Docket is
(202) 566-1742.
Electronic Access. You may access this Federal Register document
electronically through the EPA Internet under the Federal Register
listings at http://www.epa.gov/fedrgstr/.
An electronic version of the public docket is available through
EPA's electronic public docket and comment system, EPA Dockets. You may
use EPA Dockets at http://www.epa.gov/edocket/ to view public comments,
access the index listing of the contents of the official public docket,
and to access those documents in the public docket that are available
electronically. Although not all docket materials may be available
electronically, you may still access any of the publicly available
docket materials through the docket facility located above. Once in the
system, select search, then key in the appropriate docket
identification number.
Comments. We are publishing the direct final rule without prior
proposal because we view this as a noncontroversial amendment and do
not anticipate adverse comments. However, in the proposed rules section
of this Federal Register, we are publishing a separate document that
will serve as the proposal in the event that adverse comments are
filed. If we receive any adverse comments on a specific element of the
direct final rule, we will publish a timely withdrawal in the Federal
Register informing the public which amendments will become effective
and which amendments are being withdrawn due to adverse comment. We
will address all public comments in a subsequent final rule based on
the proposed rule. Any of the distinct amendments in this direct final
rule for which we do not receive adverse comment will become effective
on the date set out above. We will not institute a second comment
period on the direct final rule. Any parties interested in commenting
must do so at this time.
World Wide Web (WWW). In addition to being available in the docket,
an electronic copy of the direct final rule is also available on the
WWW through the Technology Transfer Network (TTN). Following signature,
a copy of the promulgated direct final rule will be posted on the TTN's
policy and

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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. If more information
regarding the TTN is needed, call the TTN HELP line at (919) 541-5384.
Outline. The information presented in this preamble is organized as
follows:

I. Background
II. Discussion of Revisions
A. Continuous Monitoring Options
B. Optional Fuel-Bound Nitrogen Allowance
C. Frequency of Fuel Nitrogen and Sulfur Content Sampling
D. Steam Injection
E. Test Methods for Sulfur Content and Nitrogen Content of Fuel
F. Performance Testing
G. Measurement after Duct Burner
H. Option to Not Use International Organization for
Standardization (ISO) Correction
I. Accuracy of Continuous Monitoring System (CMS) for Fuel
Consumption and the Water or Steam to Fuel Ratio
J. Deviations, Excess Emissions, and Monitor Downtime
K. Other Clarifications
III. Environmental and Economic Impacts
IV. 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 Risks and Safety Risks
H. Executive Order 13211: Actions that Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer Advancement Act
J. Congressional Review Act

I. Background

Under section 111 of the CAA, 42 U.S.C. 7411, the EPA promulgated
standards of performance for stationary gas turbines (40 CFR part 60,
subpart GG). The standards were originally promulgated on September 10,
1979 (44 FR 52798). Since that time, many changes in the design of the
NOX emission controls used for and the composition of the
fuels fired in gas turbines have occurred. Additional test methods have
also been developed to measure emissions from gas turbines and the
sulfur content of gaseous fuels. As a result of these changes, we have
had many requests for case-by-case approvals of alternative testing and
monitoring procedures for subpart GG. We are promulgating the
amendments to subpart GG to codify the alternatives that have been
routinely approved. Additionally, we are attempting to harmonize, where
appropriate, the provisions of subpart GG with the monitoring
provisions of 40 CFR part 75, the continuous emission monitoring
requirements of the acid rain program under title IV of the CAA, since
many existing and new gas turbines are subject to both regulations.

II. Discussion of Revisions

A. Continuous Monitoring Options

Under the original provisions of subpart GG, any affected unit with
a water injection system was required to install and operate a
continuous monitoring system to monitor and record the fuel consumption
and the ratio of water to fuel being fired in the turbine. These
operating parameters demonstrate that a turbine continues to operate
under the same performance conditions as those documented during the
initial and any subsequent compliance tests, thus providing reasonable
assurance of compliance with the NOX standard. We are
revising the regulation to allow the use of NOX continuous
emission monitoring systems (CEMS) to demonstrate compliance, as
detailed in the following paragraphs.
Owners or operators of turbines that commenced construction,
reconstruction, or modification after October 3, 1977, but before May
29, 2003, and that use water or steam injection to control
NOX emissions can continue to use the NOX
monitoring system which is currently being used, or may elect to use a
NOX CEMS. The CEMS must be installed, operated, and
maintained according to the appropriate performance specification
requirements in 40 CFR part 60, appendix B. Alternatively, sources may
choose to use data from a NOX CEMS that is certified
according to the requirements of 40 CFR part 75. Any owners or
operators of turbines constructed, reconstructed, or modified in this
time period that do not use water or steam injection and that have
received EPA approval of an alternative monitoring strategy can
continue to follow the conditions of the petition approval.
For new turbines constructed after the effective date of the direct
final rule and using water or steam injection for NOX
control, owners/operators can elect to use either the existing
requirements for continuous water or steam to fuel ratio monitoring or
may elect to use a CEMS to monitor NOX. The CEMS must be
installed, operated, and maintained according to Performance
Specifications (PS) 2 and 3 of 40 CFR part 60, appendix B.
Alternatively, sources may choose to use data from a NOX
CEMS that is certified according to the requirements of 40 CFR part 75,
appendix A.
Owners or operators of new turbines that commence construction
after the effective date of the direct final rule and do not use water
or steam injection to control NOX emissions can use a
NOX CEMS as an alternative to continuously monitoring fuel
consumption and water or steam to fuel ratio, provided the CEMS is
installed, operated, and maintained according to PS 2 and 3 of 40 CFR
part 60, appendix B and 40 CFR 60.13 or the requirements of 40 CFR part
75, appendix A. An acceptable alternative to installation of a
NOX CEMS is continuous parameter monitoring. If this option
is chosen, owners or operators of uncontrolled diffusion flame turbines
must continuously monitor at least four parameters indicative of the
unit's NOX formation characteristics. For lean premix
turbines, continuous monitoring of parameters that indicate whether the
turbine is operating in the lean premixed combustion mode is required.
Examples of these parameters may include percentage of full load,
turbine exhaust temperature, combustion reference temperature,
compressor discharge pressure, fuel and air valve positions, dynamic
pressure pulsations, internal guide vane position, and flame detection
or flame scanner conditions. Definitions for diffusion flame turbine
and lean premix turbine have been added to the definitions section of
the final rule. Parameters that indicate proper operation of the
emission control device must be monitored for turbines that use
selective catalytic reduction. In all cases, the acceptable values and
ranges for the parameters must be established during the initial
performance test for the turbine and recorded in a parameter monitoring
plan, to be kept on-site.
If the option to use a NOX CEMS is chosen, we have
specified the minimum data requirements. For full operating hours, each
monitor must complete at least one cycle of operation (including
sampling, analyzing, and data recording) for each 15-minute quadrant of
the hour. For partial unit operating hours, one valid data point must
be obtained for each quadrant of the hour for which the unit is
operating. Two valid data points are required for hours in which
required quality assurance and maintenance activities are performed on
the CEMS. This data must be reduced to hourly averages for purposes of
identifying excess emissions. The data

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acquisition and handling system must record the hourly NOX
emissions as well as the International Organization for Standardization
(ISO) standard conditions (if applicable).
In lieu of recording the ISO standard conditions, a worst case ISO
correction factor can be calculated using historical ambient data. For
the purpose of this calculation, substitute the maximum humidity of
ambient air (Ho), minimum ambient temperature
(Ta), and minimum combustor inlet absolute pressure
(Po) into the ISO correction equation. By using worst case
parameters in this equation, the owner/operator can ensure compliance
in all situations without having to continuously monitor temperature,
humidity and pressure. Several case-by-case determinations performed by
EPA have accepted this methodology as an alternative to continuous
monitoring of atmospheric conditions.
No data generated using the data substitution methodology in 40 CFR
part 75 may be used. Instead, these periods of missing data are
identified and summarized in the excess emissions and monitoring report
required in 40 CFR 60.13. For turbines using NOX CEMS, we
have defined excess emissions as any unit operating hour during which
the 4-hour rolling average NOX concentration exceeds the
applicable emission limit.
The averaging time selected for combustion turbine NOX
CEMS to define the periods of excess emissions is a period of 4 hours
averaged each hour. The 4-hour period is representative of the overall
elapsed time in a typical EPA Method 20 of 40 CFR part 60, appendix A,
source test. This period has been found adequate to represent the
performance of combustion turbine NOX emissions and
NOX emission control systems. The 4-hour period is a
relatively short averaging time compared to 24-hour and monthly
averaging times used for other types of combustion devices to account
for the NOX emissions variability, particularly in solid
fuels. Combustion turbines typically use natural gas or No. 2
distillate oil, which have a relatively uniform fuel nitrogen content,
therefore, a relatively short averaging time such as 4 hours is
appropriate. An averaging time of 1 hour was also considered but was
rejected since 4 hours more closely represent the typical duration of a
combustion turbine stack test and includes the ability to account for a
small amount of nitrogen variability.
A 1-hour period was selected as the recurring (rolling) period for
which the 4-hour averages are calculated since it is already required
to be reported under 40 CFR part 75 and is convenient and appropriate
to use.
We are allowing the use of NOX CEMS as an alternative to
continuously monitoring fuel consumption and water or steam to fuel
ratio because the majority of new turbines do not rely on water
injection for NOX control. Therefore, for those turbines,
the monitoring originally required by subpart GG is not appropriate.
The use of a NOX CEMS will show compliance with the
NOX standard of subpart GG over all operating ranges.
Additionally, many of the units affected by subpart GG are already
required to install and certify CEMS for NOX under other
requirements, such as the acid rain monitoring regulation in 40 CFR
part 75, or through conditions in various permit requirements. To
reduce the burden on these units, we are allowing the use of CEMS units
that are certified according to the requirements of 40 CFR part 75. The
40 CFR part 75 testing procedures to certify the CEMS are nearly
identical to those in 40 CFR part 60, and 40 CFR part 75 has rigorous
quality assurance and quality control standards. We, therefore, believe
it is appropriate to allow the use of 40 CFR part 75 CEMS data for
subpart GG compliance demonstration. A definition of unit operating
hour, which includes the concepts of ``full'' and ``partial'' operating
hours, is needed to clarify how to validate an hour when using CEMS and
for the purpose of defining excess emissions, deviations, and periods
of monitor downtime.

B. Optional Fuel-Bound Nitrogen Allowance

The NOX emission standard in 40 CFR 60.332 includes a
NOX emission allowance for fuel-bound nitrogen. The use of
this allowance for fuel-bound nitrogen will be optional upon
promulgation of the direct final rule. Owners or operators will be able
to choose to accept a value of zero for the NOX emission
allowance. The NOX emission limitations in many State
permits are much more stringent than those of subpart GG. Many turbines
are required by their permits to be fired only with pipeline quality
natural gas, which is almost free of fuel-bound nitrogen. Therefore,
these facilities are not likely to use the fuel-bound nitrogen credit.

C. Frequency of Fuel Nitrogen and Sulfur Content Sampling

Several revisions to the sampling frequency requirements for fuel
nitrogen content and fuel sulfur content are being made.
1. Nitrogen Content for Turbines That Do Not Claim the Allowance for
Fuel Bound Nitrogen
We are amending subpart GG so that sources are required to monitor
the nitrogen content of the fuel being fired in the turbine only if
they claim the allowance for fuel bound nitrogen. For sources that do
not seek to use the fuel-bound nitrogen credit, the sampling
requirements to determine the daily fuel nitrogen concentrations are
not required.
2. Nitrogen and Sulfur Content for Turbines Firing Fuel Oil
The sampling frequency for determining the nitrogen and sulfur
content of fuel oil has been revised. Previously for bulk storage
fuels, sampling and analysis was required each time new fuel was added.
The requirement to sample the nitrogen and sulfur content of the fuel
each time fuel is transferred to the storage tank from any other source
can be burdensome for a facility if there are one or more large bulk
storage tanks which are filled by tanker trucks or isolated from the
turbines during the filling process. If the fuel is not fed to the
turbines during the filling process, no environmental benefit is gained
by sampling every time oil is added from a tanker truck. Similarly, no
environmental benefit is gained by sampling a tank which remains
isolated from feeding turbines until it is filled. It is less
burdensome to allow a tank to be filled completely, regardless of how
many tanker trucks it takes, and then drawing a sample of the combined
fuel. In the end, this mixture of fuel is what will be fed to the
turbines. Thus, we are eliminating the requirement to sample each time
new fuel is added and are allowing the use of any of the four sampling
options from 40 CFR part 75, appendix D. The four options are as
follows: daily sampling, flow proportional sampling, sampling from a
unit's storage tank, or sampling each delivery.
3. Sulfur Content for Turbines Firing Natural Gas
A definition for natural gas has been added to the definitions
section. It is consistent with the latest definition in 40 CFR part 72.
Owners and operators of turbines that are combusting natural gas are
now provided with alternatives to demonstrate that the fuel meets the
sulfur content requirement. We believe that sulfur sampling is
unnecessary for fuels that qualify as natural gas. As defined in the
direct final rule, natural gas contains 20.0 grains or less of total
sulfur per 100 standard cubic feet,

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which equates to about 0.06 weight percent sulfur or 600 parts per
million by weight (ppmw). When natural gas is combusted, there is no
possibility of exceeding the subpart GG sulfur limit of 0.8 weight
percent.
4. Sulfur and Nitrogen Content for Turbines Firing Gaseous Fuels Other
Than Natural Gas
Units that fire a gaseous fuel that is supplied without
intermediate bulk storage, but is not natural gas, must determine and
record the sulfur content and (if applicable) nitrogen content once per
day. Alternatively, these units may follow one of two custom sulfur
sampling schedules outlined in the direct final rule, or they may
develop a custom schedule that is approved by the Administrator. One
custom schedule requires daily sampling for 30 consecutive unit
operating days. Provided the data indicate compliance, the frequency
can then be reduced according to specific criteria. Unit operating day
is now defined in 40 CFR 60.331.
Units may also follow a custom schedule based on the 720-hour
sulfur sampling demonstration described in 40 CFR part 75, appendix D.
Under both schedules, if the margin of compliance is large, the
sampling frequency can eventually be reduced to annually. We are
codifying these two custom schedules that have routinely been approved
under the subpart GG provision that allows sources to develop custom
schedules for fuel sampling that must be approved by the Administrator.

D. Steam Injection

Sources that are using water injection currently can monitor the
ratio of water to fuel, as well as fuel consumption, to demonstrate
compliance with the NOX standard. We are allowing sources
that are using steam injection to monitor the ratio of steam to fuel
and fuel consumption to demonstrate compliance. Steam injection is
another method of NOX control, and water and steam injection
are the wet methods usually used. Steam injection monitoring is an
acceptable type of parametric emission monitoring method.

E. Test Methods for Sulfur Content and Nitrogen Content of Fuel

When subpart GG was originally promulgated, no test methods were
specified for monitoring the nitrogen content of the fuel. We are
specifying American Society of Testing and Materials (ASTM) D2597-
94(1999), ASTM D6366-99, ASTM D4629-02, or ASTM D5762-02 as acceptable
methods for liquid fuels. As the National Technology Transfer and
Advancement Act requires, we have identified these voluntary consensus
standards and are citing them for use. We are not adding any methods
for determining the fuel-bound nitrogen content of the fuel being fired
for gaseous fuels because none were identified. We do not expect any
source owner to use a gaseous fuel with sufficient fuel bound nitrogen
present to claim a credit. Any source owner proposing credit for fuel
bound nitrogen in a gaseous fuel will have to document an acceptable
method. We have amended subpart GG to allow the use of most of the
methods specified in sections 2.2.5 and 2.3.3.1.2 of 40 CFR part 75,
appendix D to determine the total sulfur content of gaseous fuel. The
alternative methods for total sulfur provide more flexibility and
harmonize with the requirements in 40 CFR part 75. The method ASTM
D3031-81 has been deleted from the final rule because it was
discontinued by the ASTM in 1990 with no replacement. If the total
sulfur content of the fuel being fired in the turbine is less than 0.4
weight percent, we are adding a provision that the following methods
may be used to measure the sulfur content of the fuel: ASTM D4084-82 or
94, D5504-01, D6228-98, or the Gas Processors Association Method 2377-
86. This provision is consistent with the provision in 40 CFR
60.13(j)(1) allowing alternatives to reference method tests to
determine relative accuracy of CEMS for sources with emission rates
demonstrated to be less than 50 percent of the applicable standard.

F. Performance Testing

To measure the NOX and diluent concentration during the
performance test, we are adding EPA Method 7E of 40 CFR part 60,
appendix A used in conjunction with EPA Method 3 or 3A of 40 CFR part
60, appendix A as an acceptable alternative to EPA Method 20. In
addition, we are adding ASTM D6522-00 as another alternative to EPA
Method 20. If ASTM D6522-00 or EPA Methods 7E and 3 or 3A are used,
sampling must be conducted at a minimum of three traverse points, due
to concerns about potential stratification of pollutant concentrations
in the turbine stack.
Subpart GG previously required the NOX initial
compliance testing to be conducted at four different loads across the
unit's operating range. This testing was required because of the
difficulty in predicting which operating load will represent worst case
conditions when monitoring operational data. Testing, therefore, was
done across the operating range to determine the water to fuel ratio
and fuel consumption needed to maintain NOX compliance
across the unit's normal operating range. One of the tests was required
to be conducted at 100 percent of peak load. We are revising the final
rule to allow one test point at 90 to 100 percent of peak load. Due to
conditions that are beyond the control of the turbine operator, such as
ambient conditions, it is often not possible for a turbine to be
operated at 100 percent of the manufacturer's design capacity.
Therefore, the requirement to test at 100 percent of peak load has been
made more flexible.
Another change is that the initial performance test can be
performed at 90 to 100 percent of peak load only, instead of at four
different loads, if the owner or operator chooses to use the
NOX CEMS monitoring option. The NOX CEMS will
provide realtime data on NOX emissions for any given time of
operation. This data provides credible evidence which can be used to
determine the unit's compliance status on a continuous basis following
the initial test. The availability of this continuous information
through the use of NOX CEMS after the initial performance
testing justifies testing at a single load for the initial compliance
testing. We are also clarifying how data collected during a relative
accuracy test audit (RATA) of the NOX CEMS may be used to
demonstrate compliance with the performance tests required by 40 CFR
60.8. The RATA consists of a minimum of nine 21-minute runs using EPA
reference test methods, for a total of 189 minutes or just over 3
hours. This amount of sampling accompanied by sampling at multiple
traverse points during a RATA provides enough representative emissions
data to determine the unit's compliance status.
Finally, a statement has been added to clarify that if the turbine
combusts both oil and gas, separate performance testing is required for
each type of fuel combusted by the turbine, except for emergency fuel.
We believe that this is appropriate due to the fact that NOX
emissions vary by fuel type.

G. Measurement After Duct Burner

For sources that are combined cycle turbine systems using
supplemental heat, we have added an option that the turbine
NOX emissions may be measured after the duct burner rather
than directly after the turbine. No additional NOX allowance
is given. A definition for duct burner has also been added to the
definitions section of the final rule. For combined cycle units, there
are several concerns with testing and monitoring NOX at the
turbine

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outlet. For example, it is questionable whether the turbine outlet
location is suitable for installation of CEMS. Moreover, due to the
high temperature and pressure of the turbine exhaust at that location,
it may be difficult to conduct an EPA Method 20 performance test at the
turbine outlet of a combined cycle unit. In addition, any combined
cycle units that are subject to NOX CEMS requirements for 40
CFR part 75 or subparts Da and Db of 40 CFR part 60 will most likely
have installed the CEMS after the duct burner, on the heat recovery
steam generator (HRSG) stack. Another reason to allow measurement of
NOX emissions after the duct burner is that add-on
NOX control systems such as selective catalytic reduction
(SCR) are generally located after the duct burner; turbine
NOX performance testing should be conducted after the
NOX control device and would, therefore, include emissions
from the duct burner.

H. Option To Not Use International Organization for Standardization
(ISO) Correction

We have added an option to not use the ISO correction equation for
the following units: lean premix combustor turbines, units used in
association with heat recovery steam generators equipped with duct
burners, and units with add-on emission controls. This option was added
based on discussions with the Gas Turbine Association (GTA). The GTA
indicated in letters to EPA on April 16, 2002, and May 30, 2002, that
the ISO correction equation was not necessary for these units. These
letters can be found in the docket.

I. Accuracy of Continuous Monitoring System (CMS) for Fuel Consumption
and the Water or Steam to Fuel Ratio

The requirement that the CMS for the fuel consumption and water or
steam to fuel ratio for the turbine be accurate to within 5 percent has
been removed. The numerical value of water to fuel ratio that serves as
a surrogate for the acceptable NOX concentration is
established at each facility. This is accomplished by simultaneously
measuring the NOX concentration and using a CMS to monitor
the water or steam to fuel ratio that achieves that NOX
level at various turbine loads at the specific facility during a
performance test. This calibration serves to assure that if the water
or steam to fuel ratio is maintained above this surrogate value using
the same CMS, then acceptable NOX concentration levels are
attained even if the actual numerical value is not correct. Hence, the
requirement to be accurate within plus or minus 5 percent is not
necessary.

J. Deviations, Excess Emissions, and Monitor Downtime

The excess emission reporting provisions under 40 CFR 60.334 have
been revised to include definitions of deviations, excess emissions,
and monitor downtime periods for the various emissions and parameter
monitoring requirements. To be consistent with other 40 CFR part 60
rules, we are including provisions for deviations, which are associated
with parametric monitoring. A deviation indicates the possibility that
an excess emission has occurred. Periods of monitor downtime were not
previously defined, so we have added definitions for those periods. New
provisions have been added for CEMS and parametric monitoring for
certain units; therefore, it is necessary to define the excess
emissions, deviations, and monitor downtime for turbines using these
new monitoring options.

K. Other Clarifications

Several other minor clarifications have been made to the final
rule. They are as follows: (1) Indicated that the sulfur content
standard in 40 CFR 60.333(b) of 0.8 percent by weight is equivalent to
8000 ppmw; (2) clarified the NOX standard in 40 CFR
60.332(a)(1) to indicate that it is an emission concentration and
should be ISO corrected (if required); and (3) clarified the
NOX emission concentration equation in 40 CFR 60.335(b)(1)
to indicate it is a concentration instead of a rate and that it is on a
dry basis.

III. Environmental and Economic Impacts

We believe that the amendments will not have any significant
economic or environmental impacts. The changes have been made primarily
to codify routine testing and monitoring alternatives that have
previously been approved by us. We are not introducing any new emission
limitations, control requirements, or monitoring requirements. We are
attempting to reduce the testing, monitoring, and reporting burden by
harmonizing with the requirements of 40 CFR part 75, since many gas
turbines are subject to it as well as subpart GG.

IV. 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, we have determined
that the amendments do not constitute a ``significant regulatory
action'' because they do not meet any of the above criteria.
Consequently, this action was not submitted to OMB for review under
Executive Order 12866.

B. Paperwork Reduction Act

This action does not impose any new information collection burden.
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 are listed in 40 CFR part 9 and 48 CFR chapter 15.
The revisions contain no changes to the information collection
requirements of the current New Source Performance Standards (NSPS)
that would increase the burden to sources, and the currently approved
OMB information collection

[[Page 17995]]

requests are still in force for the amended rule. Some changes in the
final rule, such as allowing the use of CEMS to measure NOX
emissions, are provided as an option to sources, and should reduce
burden to those sources who already have a CEMS in place for other
regulatory reasons, such as the Acid Rain requirements in 40 CFR part
75. Other changes, such as the allowance of parametric monitoring in
place of water to fuel ratio monitoring, do not result in additional
recordkeeping and reporting requirements beyond those already required.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA), as Amended by the Small
Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C.
601 et seq., generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment
rulemaking requirements under the Administrative Procedure Act or any
other statute, unless the agency certifies that the rule will not have
a significant economic impact on a substantial number of small
entities. Small entities include small businesses, small organizations,
and small governmental jurisdictions.
For purposes of assessing the impacts of the direct 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, or fewer than 4
billion kW-hr per year of electricity usage, depending on the size
definition for the affected North American Industry Classification
System (NAICS) code; (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 six NAICS codes may be affected by the direct final
rule, and the small business definition applied to each industry by
NAICS code is that listed in the Small Business Administration (SBA)
size standards (13 CFR part 121).
After considering the economic impacts of the direct final rule on
small entities, we certify that this action will not have a significant
economic impact on a substantial number of small entities. This
certification is based primarily upon the estimated cost savings to
turbine owners and operators as a result of the revisions to 40 CFR
part 60, subpart GG that are presented earlier in this preamble. These
cost savings will be experienced by turbines owned and operated by
small entities as well as large ones. Using the existing combustion
turbines inventory as a measure of which industries may install new
turbines in the future, presuming the existing mix of combustion
turbines currently is a good approximation of the mix of turbines that
will be installed and affected by the direct final rule up to 2007, 2.5
percent of new turbines overall will likely be owned and operated by
small entities. Of these entities, a majority of these are owned and
operated by small communities.
For more information on the results of the analysis of small entity
impacts, please refer to the economic impact analysis in the docket.

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
one year.
Before promulgating an EPA rule for which a written statement is
needed, section 205 of the UMRA generally requires EPA to identify and
consider a reasonable number of regulatory alternatives and adopt the
least costly, most cost effective, or least burdensome alternative that
achieves the objective of the rule. The provisions of section 205 do
not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost effective, or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed under
section 203 of the UMRA a small government agency plan. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of EPA regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
The EPA has determined that the direct final rule amendments
contain 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 one year. Thus, the amendments
are not subject to the requirements of sections 202 and 205 of the
UMRA. In addition, EPA has determined that the amendments contain 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 direct
final rule amendments are not subject to the requirements of section
203 of the UMRA.

E. Executive Order 13132: Federalism

Executive Order 13132, entitled ``Federalism'' (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 direct 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. Today's action
codifies alternative testing and monitoring procedures that have
routinely been approved by EPA. There are minimal, if any, impacts
associated with this action. Thus, Executive Order 13132 does not apply
to the direct final rule amendments.

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

Executive Order 13175, entitled ``Consultation and Coordination
with Indian Tribal Governments'' (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

[[Page 17996]]

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 direct 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 gas turbines owned or operated by Indian
tribal governments. However, if there are any, the effect of the direct
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 direct final rule.

G. Executive Order 13045: Protection of Children From Environmental
Health Risks 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.
We interpret Executive Order 13045 as applying only to those
regulatory actions that are based on health or safety risks, such that
the analysis required under section 5-501 of the Executive Order has
the potential to influence the regulation. The direct final rule is not
subject to Executive Order 13045 because it is based on technology
performance and not on health or safety risks.

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

The direct final rule is not subject to Executive Order 13211,
``Actions Concerning Regulations that Significantly Affect Energy
Supply, Distribution, or Use'' because it is not a significant
regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Public Law No. 104-113; 15 U.S.C. 272 note)
directs the 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 direct final rule involves technical standards. The EPA cites
the following standards in the direct final rule: EPA Methods 3, 3A,
7E, and 20 of 40 CFR part 60, appendix A; PS 2 and 3 of 40 CFR part 60,
appendix B.
In addition, the direct final rule cites the following voluntary
consensus standards: ASTM D129-00 (incorporated by reference (IBR) in
40 CFR part 60, section 17), ASTM D1072-80 or -90 (Reapproved 1999)
(IBR in 40 CFR part 60, section 17), ASTM D1266-98 (IBR in 40 CFR part
60, section 17), ASTM D1552-01 (IBR in 40 CFR part 60, section 17),
ASTM D2597-94 (Reapproved 1999), ASTM D2622-98 (IBR in 40 CFR part 60,
section 17), ASTM D3246-81 or -92 or -96 (IBR in 40 CFR part 60,
section 17), ASTM D4084-82 or -94 (IBR in 40 CFR part 60, section 17),
ASTM D4294-02, ASTM D4468-85 (Reapproved 2000), ASTM D4629-02, ASTM
D5453-00, ASTM D5504-01, ASTM D5762-02, ASTM D6228-98, ASTM D6366-99,
ASTM D6522-00, ASTM D6667-01; and Gas Processors Association Standard
2377-86.
Consistent with the NTTAA, EPA conducted searches to identify
voluntary consensus standards in addition to the EPA methods. No
applicable voluntary consensus standards were identified for EPA PS 3.
The search and review results have been documented and are placed in
the docket (OAR-2002-0053) for the direct final rule.
One voluntary consensus standard was found acceptable as an
alternative to EPA test methods for the purposes of the direct final
rule. The voluntary consensus standard ASTM D6522-00, ``Standard Test
Method for the 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' was identified as an acceptable alternative to EPA
Methods 3A, 7E, and 20 for identifying nitrogen oxide and oxygen
concentration for the direct final rule when the fuel is natural gas.
In addition to the voluntary consensus standards EPA uses in the
direct final rule, the search for emissions measurement procedures
identified six other voluntary consensus standards. The EPA determined
that these six standards identified for measuring emissions subject to
emission standards were impractical alternatives to EPA test methods
for the purposes of the direct final rule. Therefore, EPA does not
intend to adopt these standards for this purpose. The reasons for this
determination for the six methods are in the docket.
Section 60.335 to 40 CFR part 60, subpart GG, lists the EPA testing
methods included in the final rule. Under 40 CFR 63.7(f) and 63.8(f), a
source may apply to EPA for permission to use alternative test methods
or alternative monitoring requirements in place of any of the EPA
testing methods, performance specifications, or procedures.

J. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 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. The EPA will submit a report containing the direct 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 direct final rule in the Federal Register.
The direct final rule is not a ``major rule'' as defined by 5 U.S.C.
804(2).

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.

[[Page 17997]]

Dated: March 27, 2003.
Christine Todd Whitman,
Administrator.

0
For the reasons stated in the preamble, title 40, chapter I, part 60,
of the Code of Federal Regulations is amended to read 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:
0
a. Removing and reserving paragraph (a)(38);
0
b. Revising paragraph (a) introductory text;
0
c. Revising paragraph (a)(8);
0
d. Revising paragraph (a)(15);
0
e. Revising paragraph (a)(18);
0
f. Revising paragraph (a)(20);
0
g. Revising paragraph (a)(33);
0
h. Revising paragraph (a)(43);
0
i. Revising paragraph (a)(50);
0
j. Adding paragraphs (a)(65) through (a)(75); and
0
k. Adding paragraph (m).
The revisions and additions 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.
* * * * *
(8) ASTM D129-64, 78, 95, 00, Standard Test Method for Sulfur in
Petroleum Products (General Bomb Method), IBR approved for Appendix A:
Method 19, 12.5.2.2.3; Sec. Sec. 60.106(j)(2) and 60.335(b)(10)(i).
* * * * *
(15) 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 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).
* * * * *
(20) ASTM D1552-83, 95, 01, Standard Test Method for Sulfur in
Petroleum Products (High-Temperature Method), IBR approved for Appendix
A: Method 19, Section 12.5.2.2.3; Sec. Sec. 60.106(j)(2) and
60.335(b)(10)(i).
* * * * *
(33) 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).
* * * * *
(43) 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).
* * * * *
(50) 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).
* * * * *
(65) 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).
(66) 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).
(67) ASTM D4468-85 (Reapproved 2000), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry, IBR approved for Sec. 60.335(b)(10)(ii).
(68) 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).
(69) 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).
(70) 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. 60.334(h)(1).
(71) 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).
(72) 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).
(73) 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).
(74) 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).
(75) 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).
* * * * *
(m) This material is available for purchase from at least one of
the following addresses: The Gas Processors Association, 6526 East 60th
Street, Tulsa, OK, 74145; or Information Handling Services, 15
Inverness Way East, P.O. Box 1154, Englewood, CO 80150-1154. You may
inspect a copy at EPA's Air and Radiation Docket and Information
Center, Room B108, 1301 Constitution Ave., NW., Washington, DC 20460.
(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. 60.334(h)(1).
(2) [Reserved]
* * * * *

Subpart GG--[AMENDED]

0
3. Section 60.331 is amended by adding paragraphs (s) through (aa) to
read as follows:

Sec. 60.331 Definitions.

* * * * *
(s) 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.
(t) Deviation means a unit operating hour during which the recorded
value of a particular monitored parameter is outside the acceptable
range specified in the parameter monitoring plan for the affected unit.
(u) Excess emissions means a specified averaging period over which
either (1) the NOX emissions are higher

[[Page 17998]]

than the applicable emission limit in Sec. 60.332; or (2) the total
sulfur content of the fuel being combusted in the affected facility
exceeds the limit specified in Sec. 60.333.
(v) 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. Natural gas contains 20.0 grains or less of total sulfur
per 100 standard cubic feet. Additionally, natural gas must either be
composed of at least 70 percent methane by volume or have a gross
calorific value between 950 and 1100 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.
(w) Duct burner means a device that combusts fuel and that is
placed in the exhaust duct from another source, such as a stationary
gas 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.
(x) 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.
(y) 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.
(z) 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.

0
4. Section 60.332 is amended by:
0
a. Revising the terms to the equations in paragraphs (a)(1) through
(3);
0
b. Redesignating paragraph (a)(3) as (a)(4); and
0
c. Adding a new paragraph (a)(3).
The revisions and additions read as follows:

Sec. 60.332 Standard for nitrogen oxides.

(a) * * *
(1) * * *

where:

STD = allowable ISO corrected (if required as given in 60.335(b)(1))
NOX emission concentration (percent by volume at 15 percent
oxygen and on a dry basis),
Y = manufacturer's rated heat rate at manufacturer's rated load
(kilojoules per watt hour) or, actual measured heat rate based on lower
heating value of fuel as measured at actual peak load for the facility.
The value of Y shall not exceed 14.4 kilojoules per watt hour, and
F = NOX emission allowance for fuel-bound nitrogen as
defined in paragraph (a)(4) of this section.

(2) * * *

where:

(3) The use of F in Sec. 60.332(a)(1) and (2) is optional. That
is, the owner or operator may choose to apply a NOX
allowance for fuel-bound nitrogen and determine the appropriate F-value
in accordance with Sec. 60.332(a)(4) or may accept an F-value of zero.
(4) If the owner or operator elects to apply a NOX
emission allowance for fuel-bound nitrogen, F shall be defined
according to the nitrogen content of the fuel during the most recent
performance test required under Sec. 60.8 as follows:

------------------------------------------------------------------------
Fuel-bound nitrogen (percent by weight) F (NOX percent by volume)
------------------------------------------------------------------------
N<=0.015.................................. 0
0.0150.25.......................... 0.005
------------------------------------------------------------------------

where:

N = the nitrogen content of the fuel (percent by weight).

or:

Manufacturers may develop and submit to EPA custom fuel-bound
nitrogen allowances for each gas turbine model they manufacture. These
fuel-bound nitrogen allowances shall be substantiated with data and
must be approved for use by the Administrator before the initial
performance test required by Sec. 60.8. Notices of approval of custom
fuel-bound nitrogen allowances will be published in the Federal
Register.
* * * * *

0
5. Section 60.333 is amended by revising paragraph (b) to read as
follows:

Sec. 60.333 Standard for sulfur dioxide.

* * * * *
(b) No owner or operator subject to the provisions of this subpart
shall burn in any stationary gas turbine any fuel which contains total
sulfur in excess of 0.8 percent by weight (8000 ppmw).

0
6. Section 60.334 is amended by:
0
a. Revising paragraphs (a) and (b);
0
b. Redesignating paragraph (c) as paragraph (j);
0
c. Adding a new paragraph (c);
0
d. Adding paragraphs (d) through (i);
0
e. Revising newly designated paragraphs (j) introductory text, (j)(1)
and (j)(2); and
0
f. Adding paragraph (j)(5).
The revisions and additions read as follows:

Sec. 60.334 Monitoring of operations.

(a) Except as provided in paragraph (b) of this section, the owner
or operator of any stationary gas turbine subject to the provisions of
this subpart and using water or steam injection to control
NOX emissions shall install, certify 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.
(b) The owner or operator of any stationary gas turbine that
commenced construction, reconstruction or modification after October 3,
1977, but before May 29, 2003, and which uses water or steam injection
to control NOX emissions may, as an alternative to operating
the continuous monitoring system described in paragraph (a) of this
section, install, certify, maintain, operate, and quality-assure a
continuous emission monitoring system (CEMS) consisting of
NOX and O2 monitors. If this option is chosen,
the CEMS shall be installed, certified, maintained, operated and
quality-assured as follows:
(1) Each CEMS must be installed and certified according to PS 2 and
3 (for diluent) of 40 CFR part 60, appendix B or in accordance with the
requirements of appendix A to part 75 of this chapter. The relative
accuracy test audit (RATA) of the NOX and O2
monitors may be performed individually or on a combined basis, i.e.,
the relative accuracy tests of the CEMS may be performed either:
(i) On a ppm basis (for NOX) and a percent O2
basis for oxygen; or

[[Page 17999]]

(ii) On a ppm at 15 percent O2 basis.
(2) As specified in Sec. 60.13(e)(2), during each full unit
operating hour, each 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 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 to validate the hour.
(3) For purposes of identifying excess emissions, CEMS data must be
reduced to hourly averages as specified in Sec. 60.13(h).
(i) For each unit operating hour in which a valid hourly average,
as described in paragraph (b)(2) of this section, is obtained for both
NOX and O2, the data acquisition and handling
system must calculate and record the hourly NOX emissions in
the units of the applicable NOX emission standard under
Sec. 60.332(a), i.e., percent NOX by volume, dry basis,
corrected to 15 percent O2 and International Organization
for Standardization (ISO) standard conditions (if required as given in
Sec. 60.335(b)(1)).
(ii) A worst case ISO correction factor may be calculated and
applied using historical ambient data. For the purpose of this
calculation, substitute the maximum humidity of ambient air
(Ho), minimum ambient temperature (Ta), and
minimum combustor inlet absolute pressure (Po) into the ISO
correction equation.
(iii) The missing data substitution methodology provided for at 40
CFR Part 75, subpart D may not be used for purposes of identifying
excess emissions. Instead periods of missing CEMS data are to be
reported as monitor downtime in the excess emissions and monitoring
performance report required in Sec. 60.7(c).
(4) Data from the CEMS shall be quality-assured, either in
accordance with Sec. 60.13, or in accordance with appendix B to part
75 of this chapter (or, if applicable, Sec. 75.74(c)(2) and (3) of
this chapter).
(c) For any new turbine that commenced construction, reconstruction
or modification after October 3, 1977, but before May 29, 2003, and
which does not use steam or water injection to control NOX
emissions, the owner or operator may, for purposes of determining
excess emissions, use a CEMS that meets the requirements of paragraph
(b) of this section. Also, if the owner or operator has previously
submitted and received EPA approval of a petition for an alternative
procedure of continuously monitoring compliance with the applicable
NOX emission limit under Sec. 60.332, that approved
procedure may continue to be used, even if it deviates from paragraph
(a) of this section.
(d) The owner or operator of any new turbine constructed after May
29, 2003, and which uses water or steam injection to control
NOX emissions may elect to use either the requirements in
paragraph (a) of this section for continuous water or steam to fuel
ratio monitoring or may use a NOX CEMS installed, certified,
operated, maintained, and quality-assured as described in paragraph (b)
of this section.
(e) The owner or operator of any new turbine that commences
construction after May 29, 2003, and which does not use water or steam
injection to control NOX emissions may elect to use a
NOX CEMS installed, certified, operated, maintained, and
quality-assured as described in paragraph (b) of this section. An
acceptable alternative to installing a CEMS is described in paragraph
(f) of this section.
(f) The owner or operator of a new turbine who elects not to
install a CEMS under paragraph (e) of this section, may instead perform
continuous parameter monitoring as follows:
(1) For a diffusion flame turbine without add-on selective
catalytic reduction controls (SCR), the owner or operator shall define
at least four parameters indicative of the unit's NOX
formation characteristics and shall monitor these parameters
continuously.
(2) For any lean premix stationary combustion turbine, the owner or
operator shall continuously monitor the appropriate parameters to
determine whether the unit is operating in the lean premixed (low-
NOX) combustion mode. The parameters described in Sec.
75.19(c)(1)(iv)(H)(2) of this chapter are acceptable for this purpose.
(3) For any turbine that uses SCR to reduce NOX
emissions, the owner or operator shall continuously monitor appropriate
parameters to verify the proper operation of the emission controls.
(g) The steam or water to fuel ratio or other parameters that are
continuously monitored as described in paragraphs (a), (d) or (f) of
this section shall be monitored during the performance test required
under Sec. 60.8, to establish acceptable values and ranges. The owner
or operator shall 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 shall include the
parameter(s) monitored and the acceptable range(s) of the parameter(s)
as well as the basis for designating the parameter(s) and acceptable
range(s).
(h) The owner or operator of any stationary gas turbine subject to
the provisions of this subpart:
(1) Shall monitor the total sulfur content of the fuel being fired
in the turbine, except as provided in paragraph (h)(3) of this section.
The sulfur content of the fuel must be determined using total sulfur
methods described in Sec. 60.335(b)(10). Alternatively, if the total
sulfur content of the gaseous fuel during the most recent performance
test was less than 0.4 weight percent (4000 ppmw), ASTM D4084-82, 94,
D5504-01, D6228-98, or Gas Processors Association Standard 2377-86 (all
of which are incorporated by reference-see Sec. 60.17), which measure
the major sulfur compounds may be used; and
(2) Shall monitor the nitrogen content of the fuel combusted in the
turbine, if the owner or operator claims an allowance for fuel bound
nitrogen (i.e., if an F-value greater than zero is being or will be
used by the owner or operator to calculate STD in Sec. 60.332). The
nitrogen content of the fuel shall be determined using methods
described in Sec. 60.335(b)(9) or an approved alternative.
(3) Notwithstanding the provisions of paragraph (h)(1) of this
section, the owner or operator may elect not to monitor the total
sulfur content of the gaseous fuel combusted in the turbine, if the
gaseous fuel is demonstrated to meet the definition of natural gas in
Sec. 60.331(v), regardless of whether an existing custom schedule
approved by the administrator for subpart GG requires such monitoring.
The owner or operator shall use one of the following sources of
information to make the required demonstration:
(i) The gas quality characteristics in a current, valid purchase
contract, tariff sheet or transportation contract for the gaseous fuel,
specifying that the maximum total sulfur content of the fuel is 20.0
grains/100 scf or less; or
(ii) Representative fuel sampling data which show that the sulfur
content of the gaseous fuel does not exceed 20 grains/100 scf. 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.
(4) For any new turbine that commenced construction, reconstruction
or modification after October 3, 1977, but before May 29, 2003, and for
which a custom fuel monitoring schedule has previously

[[Page 18000]]

been approved, the owner or operator may, without submitting a special
petition to the Administrator, continue monitoring on this schedule.
(i) The frequency of determining the sulfur and nitrogen content of
the fuel shall be as follows:
(1) Fuel oil. For fuel oil, use one of the total sulfur sampling
options and the associated sampling frequency described in sections
2.2.3, 2.2.4.1, 2.2.4.2, and 2.2.4.3 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). If an emission allowance is being
claimed for fuel-bound nitrogen, the nitrogen content of the oil shall
be determined and recorded once per unit operating day.
(2) Gaseous fuel. Any applicable nitrogen content value of the
gaseous fuel shall be determined and recorded once per unit operating
day. For owners and operators that elect not to demonstrate sulfur
content using options in paragraph (h)(3) of this section, and for
which the fuel is supplied without intermediate bulk storage, the
sulfur content value of the gaseous fuel shall be determined and
recorded once per unit operating day.
(3) Custom schedules. Notwithstanding the requirements of paragraph
(i)(2) 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 (i)(3)(i) and (i)(3)(ii) 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. 60.333.
(i) The two custom sulfur monitoring schedules set forth in
subparagraphs (A) through (D) of this paragraph, (i)(3)(i), and in
paragraph (i)(3)(ii) of this section are acceptable, without prior
Administrative approval:
(A) 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
(i)(3)(i)(B), (C), or (D) of this section, as applicable.
(B) If none of the 30 daily measurements of the fuel's total sulfur
content exceeds 0.4 weight percent (4000 ppmw), 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
between 0.4 and 0.8 weight percent (4000 and 8000 ppmw), follow the
procedures in paragraph (i)(3)(i)(C) of this section. If any
measurement exceeds 0.8 weight percent (8000 ppmw), follow the
procedures in paragraph (i)(3)(i)(D) of this section.
(C) If at least one of the 30 daily measurements of the fuel's
total sulfur content is between 0.4 and 0.8 weight percent (4000 and
8000 ppmw), but none exceeds 0.8 weight percent (8000 ppmw), then:
(1) Collect and analyze a sample every 30 days for three months. If
any sulfur content measurement exceeds 0.8 weight percent (8000 ppmw),
follow the procedures in paragraph (i)(3)(i)(D) of this section.
Otherwise, follow the procedures in paragraph (i)(3)(i)(C)(2) of this
section.
(2) Begin monitoring at 6-month intervals for 12 months. If any
sulfur content measurement exceeds 0.8 weight percent (8000 ppmw),
follow the procedures in paragraph (i)(3)(i)(D) of this section.
Otherwise, follow the procedures in paragraph (i)(3)(i)(C)(3) of this
section.
(3) Begin monitoring at 12-month intervals. If any sulfur content
measurement exceeds 0.8 weight percent (8000 ppmw), follow the
procedures in paragraph (i)(3)(i)(D) of this section. Otherwise,
continue to monitor at this frequency.
(D) If a sulfur content measurement exceeds 0.8 weight percent
(8000 ppmw), immediately begin daily monitoring according to paragraph
(i)(3)(i)(A) of this section. Daily monitoring shall continue until 30
consecutive daily samples, each having a sulfur content no greater than
0.8 weight percent (8000 ppmw), are obtained. At that point, the
applicable procedures of paragraph (i)(3)(i)(B) or (C) of this section
shall be followed.
(ii) 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:
(A) If the maximum fuel sulfur content obtained from the 720 hourly
samples does not exceed 20 grains/100 scf (i.e., the maximum total
sulfur content of natural gas as defined in Sec. 60.331(v)), no
additional monitoring of the sulfur content of the gas is required, for
the purposes of this subpart.
(B) 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 0.4
weight percent (4000 ppmw), then the minimum required sampling
frequency shall be one sample at 12 month intervals.
(C) If any sample result exceeds 0.4 weight percent sulfur (4000
ppmw), but none exceeds 0.8 weight percent sulfur (8000 ppmw), follow
the provisions of paragraph (i)(3)(i)(C) of this section.
(D) If the sulfur content of any of the 720 hourly samples exceeds
0.8 weight percent (8000 ppmw), follow the provisions of paragraph
(i)(3)(i)(D) of this section.
(j) For each affected unit required to continuously monitor
parameters or emissions, or to periodically determine the fuel sulfur
content or fuel nitrogen content under this subpart, the owner or
operator shall submit reports of excess emissions (or deviations, as
applicable) and monitor downtime, in accordance with Sec. 60.7(c). For
the purpose of reports required under Sec. 60.7(c), periods of excess
emissions (or deviations) and monitor downtime that shall be reported
are defined as follows:
(1) Nitrogen oxides.
(i) For turbines using water or steam to fuel ratio monitoring:
(A) A deviation shall be any unit operating hour for which the
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. 60.332, 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 shall also be considered a deviation.
(B) A period of monitor downtime shall be 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.
(C) Each report shall include the average steam or water to fuel
ratio, average fuel consumption, ambient conditions (temperature,
pressure, and humidity), gas turbine load, and (if applicable) the
nitrogen content of the fuel during each deviation.
(ii) If the owner or operator elects to take an emission allowance
for fuel bound nitrogen, then deviations and periods of monitor
downtime are as described in paragraphs (j)(1)(ii)(A) and (B) of this
section.
(A) A deviation shall be the period of time during which the fuel-
bound nitrogen (N) is greater than the value

[[Page 18001]]

measured during the performance test required in Sec. 60.8 and used to
determine the allowance. The deviation begins on the date and hour of
the sample which shows that N is greater than the performance test
value, and ends with the date and hour of a subsequent sample which
shows a fuel nitrogen content less than or equal to the performance
test value.
(B) 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 that a required sample is taken, if invalid results
are obtained. The period of monitor downtime ends on the date and hour
of the next valid sample.
(iii) For turbines using NOX and O2 CEMS:
(A) An hour of excess emissions shall be any unit operating hour in
which the 4-hour rolling average NOX concentration exceeds
the applicable emission limit in Sec. 60.332(a)(1) or (2). For the
purposes of this subpart, a ``4-hour rolling average NOX
concentration'' is the arithmetic average of the quality-assured
average NOX concentration measured by the CEMS for a given
hour (corrected to 15 percent O2 and, if required under
Sec. 60.335(b)(1), to ISO standard conditions) and the three quality-
assured unit operating hour average NOX concentrations
immediately preceding that unit operating hour.
(B) A period of monitor downtime shall be any unit operating hour
in which sufficient data are not obtained to validate the hour, for
either NOX concentration or percent O2 (or both).
(C) Each report shall include the ambient conditions (temperature,
pressure, and humidity) at the time of the excess emission period and
(if the owner or operator has claimed an emission allowance for fuel
bound nitrogen) the nitrogen content of the fuel during the period of
excess emissions.
(iv) For turbines required under paragraph (f) of this section to
monitor combustion parameters or parameters that document proper
operation of the NOX emission controls:
(A) A deviation shall be 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.
(B) A period of monitor downtime shall be a unit operating hour in
which any of the required parametric data are either not recorded or
are invalid.
(2) Sulfur dioxide. If the owner or operator is required to monitor
the sulfur content of the fuel under paragraph (h) of this section:
(i) 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 period shall begin on the date and
hour of any sample for which the sulfur content of the fuel being fired
in the gas turbine exceeds 0.8 weight percent. The excess emission
period ends on the date and hour that a subsequent sample is taken that
demonstrates compliance with the sulfur limit.
(ii) If the option to sample each delivery of fuel oil has been
selected, the owner or operator shall 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 0.8 weight percent. The owner or operator
shall continue to use one of the other sampling options until all of
the oil from the delivery has been combusted, and shall evaluate excess
emissions according to paragraph (j)(2)(i) of this section. When all of
the fuel from the delivery has been burned, the owner or operator may
resume using the as-delivered sampling option.
(iii) 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.
* * * * *
(5) All reports required under Sec. 60.7 (c) shall be postmarked
by the 30th day following the end of each calendar quarter.

0
7. Section 60.335 is amended by:
0
a. Removing paragraphs (a), (d) and (e);
0
b. Redesignating paragraphs (b) and (c) as paragraphs (a) and (b),
respectively;
0
c. Revising the new paragraphs (a) and (b);
0
d. Redesignating paragraph (f) as paragraph (c); and
0
e. Revising the new paragraph (c)(1).
The revisions and additions read as follows:

Sec. 60.335 Test methods and procedures.

(a) The owner or operator shall conduct the performance tests
required in Sec. 60.8, using either EPA Method 20, ASTM D6522-00
(incorporated by reference, see Sec. 60.17), or EPA Method 7E and
either EPA Method 3 or 3A in appendix A to this part, to determine
NOX and diluent concentration, except as provided in Sec.
60.8(b). If ASTM D6522-00 (incorporated by reference, see Sec. 60.17)
or EPA Methods 7E and 3A (or 3) are used, the owner or operator shall
perform a stratification test for NOX and diluent pursuant
to the procedures specified in section 6.5.6.1(a) through (e) appendix
A to part 75 of this chapter. Once the stratification sampling is
completed, the owner or operator shall analyze the data using the
procedures in section 6.5.6.3(a) and (c) to determine if subsequent
RATA testing will occur along a short (0.4, 1.2 and 2.0 meters from the
stack or duct wall) or long (16.7, 50.0, and 83.3 percent of the way
across the stack or duct) reference measurement line. The short or long
reference method measurement line, as determined above, will serve in
lieu of the sampling points usually required by EPA Method 20. In no
case shall the RATA be based on fewer than three sample points as
specified in section 8.1.3.2 of PS 2 in appendix B to this part. Other
acceptable alternative reference methods and procedures are given in
paragraph (c) of this section.
(b) The owner or operator shall determine compliance with the
applicable nitrogen oxides emission limitation in Sec. 60.332 and
shall meet the performance test requirements of Sec. 60.8 as follows:
(1) For each run of the performance test, the nitrogen oxides
emission concentration (NOXO) obtained using EPA Method 20,
ASTM D6522-00 (incorporated by reference, see Sec. 60.17), or EPA
Method 7E shall be corrected to ISO standard conditions using the
following equation. Notwithstanding this requirement, use of the
correction equation is optional for: lean premix stationary combustion
turbines; units used in association with heat recovery steam generators
(HRSG) equipped with duct burners; and units equipped with add-on
emission control devices:

NOX = (NOXO) (Pr/
Po)^0.5 e^{19(Ho-0.00633)} (288[deg]K/
Ta)^1.53

where:

NOX = emission concentration of NOX at 15 percent
O2 and ISO standard ambient conditions, ppm by volume, dry
basis,
NOXO = observed NOX concentration, ppm by volume,
dry basis, at 15 percent O2, corrected using either EPA
Method 20 or Method 3 or 3A data,
Pr = reference combustor inlet absolute pressure at 101.3
kilopascals ambient pressure, mm Hg,
Po = observed combustor inlet absolute pressure at test, mm
Hg,
Ho = observed humidity of ambient air, g H2O/g
air,

[[Page 18002]]

e = transcendental constant, 2.718, and
Ta = ambient temperature, [deg]K.

(2) The 3-run performance test required by Sec. 60.8 must be
performed within +/-5 percent at 30, 50, 75, and 90-to-100 percent of
peak load or at four evenly-spaced load points in the normal operating
range of the gas turbine, including the minimum point in the operating
range and 90-to-100 percent of peak load. If the turbine combusts both
oil and gas as primary or backup fuels, separate performance testing is
required for each fuel. Notwithstanding these requirements, performance
testing is not required for any emergency fuel (as defined in Sec.
60.331).
(3) For a combined cycle turbine system with supplemental heat
(duct burner), the owner or operator may elect to measure the turbine
NOX emissions after the duct burner rather than directly
after the turbine. If the owner or operator elects to use this
alternative sampling location, the applicable NOX emission
limit in Sec. 60.332 for the combustion turbine must still be met.
(4) If water or steam injection is used to control NOX
with no additional post-combustion NOX control and the owner
or operator chooses to monitor the steam or water to fuel ratio in
accordance with Sec. 60.334(a), then that monitoring system must be
operated concurrently with each EPA Method 20, ASTM D6522-00
(incorporated by reference, see Sec. 60.17), or EPA Method 7E run and
shall be used to determine the fuel consumption and the steam or water
to fuel ratio necessary to comply with the applicable Sec. 60.332
NOX emission limit.
(5) If the owner operator elects to claim an emission allowance for
fuel bound nitrogen as described in Sec. 60.332, then concurrently
with each reference method run, a representative sample of the fuel
used shall be collected and analyzed, following the applicable
procedures described in Sec. 60.335 (b)(9). These data shall be used
to determine the maximum fuel nitrogen content for which the
established water (or steam) to fuel ratio will be valid.
(6) If the owner or operator elects to install a CEMS, the
performance evaluation of the CEMS may either be conducted separately
(as described in paragraph (b)(7) of this section) or as part of the
initial performance test of the affected unit.
(7) If the owner or operator elects to install and certify a
NOX CEMS under Sec. 60.334(e), then the initial performance
test required under Sec. 60.8 may be done in the following alternative
manner:
(i) Perform a minimum of 9 reference method runs, with a minimum
time per run of 21 minutes, at a single load level, between 90 and 100
percent of peak load.
(ii) Use the test data both to demonstrate compliance with the
applicable NOX emission limit under Sec. 60.332 and to
provide the required reference method data for the RATA of the CEMS
described under Sec. 60.334(b).
(iii) The requirement to test at three additional load levels is
waived.
(8) If the owner or operator is required under Sec. 60.334(f) to
monitor combustion parameters or parameters indicative of proper
operation of NOX emission controls, the appropriate
parameters shall 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. 60.334(g).
(9) To determine the fuel bound nitrogen content of fuel being
fired (if an emission allowance is claimed for fuel bound nitrogen),
the owner or operator may use equipment and procedures meeting the
requirements of:
(i) For liquid fuels, ASTM D2597-94 (Reapproved 1999), D6366-99,
D4629-02, D5762-02 (all of which are incorporated by reference, see
Sec. 60.17); or
(ii) For gaseous fuels, shall use analytical methods and procedures
that are accurate to within 5 percent of the instrument range and are
approved by the Administrator.
(10) If the owner or operator is required under Sec. 60.334(i)(1)
or (3) to periodically determine the sulfur content of the fuel
combusted in the turbine, a minimum of three fuel samples shall be
collected during the performance test. Analyze the samples for the
total sulfur content of the fuel using:
(i) For liquid fuels, ASTM D129-00, D2622-98, D4294-02, D1266-98,
D5453-00 or D1552-01 (all of which are incorporated by reference, see
Sec. 60.17); or
(ii) For gaseous fuels, ASTM D1072-80, 90 (Reapproved 1994); D3246-
81, 92, 96; D4468-85 (Reapproved 2000); or D6667-01 (all of which are
incorporated by reference, see Sec. 60.17). 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 prior approval of the Administrator.
(11) The fuel analyses required under paragraphs (b)(9) and (b)(10)
of this section may be performed by the owner or operator, a service
contractor retained by the owner or operator, the fuel vendor, or any
other qualified agency.
(c) * * *
(1) Instead of using the equation in paragraph (b)(1) of this
section, manufacturers may develop ambient condition correction factors
to adjust the nitrogen oxides emission level measured by the
performance test as provided in Sec. 60.8 to ISO standard day
conditions.
(2) [Reserved]

[FR Doc. 03-8150 Filed 4-11-03; 8:45 am]

BILLING CODE 6560-50-P