Standards of Performance for Stationary Gas Turbines

Note: EPA no longer updates this information, but it may be useful as a reference or resource.

[Federal Register: July 8, 2004 (Volume 69, Number 130)]
[Rules and Regulations]
[Page 41345-41364]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr08jy04-13]
[[Page 41346]]

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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[OAR-2002-0053, FRL-7780-6]
RIN 2060-AK35

AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule; amendments.

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SUMMARY: This action promulgates amendments to several sections of the
standards of performance for stationary gas turbines in 40 CFR part 60,
subpart GG. 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
(NO_X) emission control technologies and turbine design since
the standards were promulgated.

DATES: The final rule is effective July 8, 2004. The incorporation by
reference of certain publications in the final rule is approved by the
Director of the Office of the Federal Register as of July 8, 2004.

ADDRESSES: Docket. The EPA has established a docket for this action
under Docket ID No. OAR-2002-0053. All documents in the docket are
listed in EDOCKET index at http://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 Air Docket, EPA/DC, EPA West, Room
B102, 1301 Constitution Avenue, NW, Washington, DC 20460. The public
reading room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Public
Reading Room is (202) 566-1744, and the telephone number for the Air
Docket 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; 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 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. The 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. A reasonable fee may be charged for copying docket
materials.
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.regulations.gov/ 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.
World Wide Web (WWW). In addition to being available in the docket,
an electronic copy of the final rule is also available on the WWW
through the Technology Transfer Network (TTN). Following signature, a
copy of the promulgated final rule will be posted on the TTN's policy
and guidance page for newly proposed or promulgated rules at http://
www.epa.gov/ttn/oarpg. The TTN provides information and technology
exchange in various areas of air pollution control. If more information
regarding the TTN is needed, call the TTN HELP line at (919) 541-5384.
Judicial Review. Under section 307(b)(1) of the Clean Air Act
(CAA), judicial review of the final rule is available only by filing a
petition for review in the U.S. Court of Appeals for the District of
Columbia Circuit by September 7, 2004. Under section 307(d)(7)(B) of
the CAA, only an objection to a rule or procedure raised with
reasonable specificity during the period for public comment can be
raised during judicial review. Moreover, under section 307(b)(2) of the
CAA, the requirements established by the final rule may not be
challenged separately in any civil or criminal proceeding brought to
enforce these requirements.
Background Information Document. During the comment period, EPA
received 23 comment letters on the proposal and direct final rule. A
background information document (BID) (``Response to Public Comments on
Proposed Standards of Performance for Stationary Gas Turbines,'')
containing

[[Page 41347]]

EPA's responses to each public comment is available in Docket ID No.
OAR-2002-0053.
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. Excess Emissions and Monitor Downtime
K. Other Clarifications
III. Summary of Responses to Major Comments
A. Fuel Sampling/Sulfur Content
B. Monitoring
C. Test Methods and Procedures
D. ISO Correction
E. Emission Standards
F. Duct Burners
IV. Environmental and Economic Impacts
V. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Analysis
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 promulgated on September 10, 1979 (44
FR 52798). Since that time, many advances in the design of the
NO_X emission controls used 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 advances, 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.
On April 14, 2003, we published a direct final rule (68 FR 17990)
and a parallel proposal (68 FR 18003) amending the standards of
performance for stationary gas turbines (40 CFR part 60, subpart GG).
We stated in the preambles to the direct final rule and parallel
proposal that if we received adverse comments on one or more distinct
provisions of the direct final rule, we would publish a timely
withdrawal of those distinct provisions in the Federal Register. The
preamble to the direct final rule stated that the deadline for
submitting public comments was May 14, 2003, and the effective date of
the provisions would be May 29, 2003. The preamble to the proposal also
stated that if a public hearing was requested by April 24, 2003, the
hearing would be held on May 14, 2003, and the comment period would be
extended until 30 days after the date of the public hearing. Since a
public hearing was requested, the comment period was extended until
June 13, 2003. The entire direct final rule was withdrawn in order to
avoid the direct final rule becoming effective before all public
comments were received.

II. Discussion of Revisions

A. Continuous Monitoring Options

Under the original provisions of subpart GG, 40 CFR part 60, 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 NO_X standard. We
are amending the regulation to allow the use of NO_X
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 July
8, 2004, and that use water or steam injection to control
NO_X emissions can continue to use the NO_X
monitoring system which is currently being used, or may elect to use a
NO_X 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 NO_X 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 or local permitting authority approval of an alternative
monitoring strategy can continue to follow the conditions of the
petition approval.
For new turbines constructed after July 8, 2004, and using water or
steam injection for NO_X 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
NO_X. The CEMS must be installed and certified according to
Performance Specifications (PS) 2 and 3 of 40 CFR part 60, appendix B.
Alternatively, sources may choose to use data from a NO_X
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 July 8, 2004, and do not use water or steam injection to control
NO_X emissions can use a NO_X CEMS as an
alternative to continuously monitoring fuel consumption and water or
steam to fuel ratio, provided the CEMS is installed and certified
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 NO_X 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 NO_X 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

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and lean premix turbine consistent with those in the combustion turbine
final rule 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 NO_X 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. A minimum of two valid data points in two different 15-
minute quadrants 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 acquisition and handling system must record
the hourly NO_X 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 (H_o), minimum ambient temperature
(T_a), and minimum combustor inlet absolute pressure
(P_o) 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 NO_X or oxygen (O₂) CEMS data generated
using the missing data substitution procedures in 40 CFR part 75 may be
used to demonstrate compliance with the subpart GG, 40 CFR part 60,
emission limits. Instead, these periods of missing data are counted as
monitor downtime in the excess emissions and monitoring report required
under 40 CFR 60.7(c). For turbines using NO_X CEMS, we have
defined excess emissions as any unit operating hour during which the 4-
hour rolling average NO_X concentration exceeds the
applicable emission limit.
The 4-hour averaging period for defining excess emissions
approximates the amount of time typically required to conduct a
performance test of a combustion turbine using EPA Method 20. The 4-
hour averaging period is relatively short compared to 24-hour and 30-
day averaging times used for other types of combustion devices (e.g.,
boilers). However, for these other combustion units, a longer averaging
period is generally needed to account for variability in the
NO_X emissions, particularly when solid fuels are fired.
Combustion turbines typically use natural gas or diesel, which both
have relatively uniform predictable NO_X emissions.
Therefore, a shorter averaging time such as 4 hours is considered
adequate to assess compliance. An averaging time of 1 hour was also
considered, but was rejected since 4 hours more closely represents the
typical duration of a combustion turbine stack test and will account
for any minor temporal variation in the NO_X emissions.
To determine the 4-hour rolling averages, each period of 4
consecutive unit operating hours is assessed (i.e., the current unit
operating hour and the 3 unit operating hours immediately preceding it).
We are allowing the use of NO_X 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 NO_X control. Therefore, for those turbines,
the monitoring originally required by subpart GG, 40 CFR part 60, is
not appropriate. The use of a NO_X CEMS will show compliance
with the NO_X 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 NO_X 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. Therefore, 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 and periods of monitor downtime.

B. Optional Fuel-Bound Nitrogen Allowance

The NO_X emission standard in 40 CFR 60.332 includes a
NO_X emission allowance for fuel-bound nitrogen. The use of
this allowance for fuel-bound nitrogen will be optional upon July 8,
2004. Owners or operators will be able to choose to accept a value of
zero for the NO_X emission allowance. The NO_X
emission limitations in many State permits are much more stringent than
those of subpart GG of 40 CFR part 60. 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.
Nitrogen Content for Turbines That Do Not Claim the Allowance for Fuel
Bound Nitrogen
We are amending subpart GG of 40 CFR part 60 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,
sampling to determine the daily fuel nitrogen concentrations is not
required.
Nitrogen and Sulfur Content for Turbines Firing Fuel Oil
The sampling frequency for determining the nitrogen and sulfur
content of fuel oil has been amended. 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

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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.
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. Sulfur sampling is unnecessary for fuels
that qualify as natural gas. As defined in the final rule, natural gas
contains 20.0 grains or less of total sulfur per 100 standard cubic
feet, which equates to about 0.068 weight percent sulfur, or 680 parts
per million by weight (ppmw), or 338 parts per million by volume (ppmv)
at 20 degrees Celsius. (The conversion factor from grains of total
sulfur per 100 standard cubic foot (gr/scf) to ppmw and percent weight:
multiply gr/scf by 3.4 x 103 to get ppmw; divide this
product by 104 to get percent weight.) When natural gas is
combusted, there is no possibility of exceeding the subpart GG, 40 CFR
part 60, sulfur limit of 0.8 weight percent or 8000 ppmw.
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 final rule, or they may develop a
custom schedule that is approved by the EPA 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 annual. 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 EPA 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 NO_X 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 NO_X 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 of 40 CFR part 60 was 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. Under the National Technology Transfer and
Advancement Act, 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 NO_X 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.
Subpart GG of 40 CFR part 60 previously required the NO_X
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 NO_X 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 amending the final
rule to allow one test point at 90 to 100 percent of peak load, or the
highest load physically achievable in practice. 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 only at 90 to 100 percent of peak load or the highest
physically achievable load in practice, instead of at four different
loads, if the owner or operator chooses to use the NO_X CEMS
monitoring option. The NO_X CEMS will provide realtime data
on NO_X 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
NO_X CEMS after the initial performance testing justifies
testing at a single load

[[Page 41350]]

for the initial compliance testing. We are also clarifying how data
collected during a relative accuracy test audit (RATA) of the
NO_X 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.
This is appropriate due to the fact that NO_X 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
NO_X emissions may be measured after the duct burner rather
than directly after the turbine. No additional NO_X 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 NO_X at the
turbine 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 NO_X 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 NO_X emissions after the duct burner is that
add-on NO_X control systems such as selective catalytic
reduction (SCR) are generally located after the duct burner; turbine
NO_X performance testing should be conducted after the
NO_X 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 HRSG 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. In addition, in response to public comments, we are not
requiring the reporting of ambient conditions if you are not using the
ISO correction factor.

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 NO_X concentration is
established at each facility. This is accomplished by simultaneously
measuring the NO_X concentration and using a CMS to monitor
the water or steam to fuel ratio that achieves that NO_X
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 NO_X 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. Excess Emissions and Monitor Downtime

The excess emission reporting provisions under 40 CFR 60.334 have
been amended to include definitions of excess emissions and monitor
downtime periods for the various emissions and parameter monitoring
requirements. 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 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 NO_X 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
NO_X 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. Summary of Responses to Major Comments

The following sections provide a summary of the major public
comments made during the public comment period for the proposed rule. A
complete summary of the comments and responses can be found in the
Summary of Public Comments and Responses document, which is available
from several sources (see ADDRESSES section).

A. Fuel Sampling/Sulfur Content

Comment: Several commenters wanted to see changes in the fuel
sampling strategies. Some commenters wanted to see less sampling
requirements, while others wanted more stringent requirements. One
commenter felt that eliminating the daily fuel total sulfur content
sampling requirement is not environmentally beneficial, and creates a
situation where the emission of sulfur compounds is presumptive with no
measured foundation. Other commenters felt that EPA should provide
additional options to sampling for nitrogen and sulfur content in fuel
oil, particularly when the unit only combusts fuel oil on a limited
basis.
Response: We did not make any changes to the fuel sampling
requirements in the final rule. The amendments did not eliminate any
requirements for natural gas sulfur content sampling. Rather, they
provide optional (not mandatory) relief from monitoring the sulfur
content of natural gas. Natural gas is defined in the final rule as
having a sulfur content of 20 grains or less of total sulfur per 100
standard cubic feet, which equates to 0.068 weight percent sulfur, or
680 ppmw. When natural gas is combusted, there is no possibility of
exceeding the subpart GG of 40 CFR part 60 sulfur limit of 0.8 weight
percent.
The commenter is not correct in asserting that this new provision
is ``presumptive with no measured foundation.'' The final rule requires
the owner or operator to document that the fuel meets the definition of
natural gas in order to obtain the regulatory relief.
In regards to fuel oil, the revisions to Sec. 60.334(i)(1) provide
owners and operators with many options for scheduling of fuel oil
sampling. They may sample on a per delivery basis; therefore, daily
sampling is not a requirement. In addition, failure to sample
deliveries of fuel oil if no fuel

[[Page 41351]]

oil has been combusted is not an excess emission if one of the other
schedules has been retained. An owner or operator may utilize flow
proportional sampling, which would require samples only if fuel oil is
being combusted. Owners and operators are not precluded from taking one
sample for the day for all units operated during an official ``unit
operating day.'' No changes have been made to the proposed regulatory
text in response to this comment.

B. Monitoring

Comment: Several comments were received on the proposed continuous
monitoring provisions. Commenters stated that EPA should withdraw the
optional continuous emission monitoring provisions under Sec.
60.334(c), (e), and (f) for turbines that do not use water or steam
injection to comply with the applicable NO_X emission standards.
One commenter requested that EPA make clear that the choice of
whether to use a NO_X CEMS is entirely at the discretion of
the source owner or operator, even in those cases where a
NO_X CEMS is installed. The commenter also requested that EPA
make clear that nothing in the final rule is intended to impose new
requirements, or to alter or prevent other determinations regarding the
adequacy of monitoring to comply with subpart GG of 40 CFR part 60.
Some commenters recommended that EPA make clear in the final rule or
preamble that (1) alternatives approved by State and local agencies
under State authority, or delegation of authority from EPA are also
valid, and (2) these amendments do not impose any new requirements, or
require revision of existing permits, but simply provide several pre-
approved options for sources that do not want to seek case-by-case
approval.
Another commenter recommended the addition of language to Sec.
60.334(c) indicating that existing turbines under subpart GG of 40 CFR
part 60 without water or steam injection that are not required to
implement continuous direct or indirect NO_X monitoring under
their current approvals may continue to operate under the provisions of
their current approvals. The commenter stated that an annual
NO_X stack test could serve as an appropriate alternative to
a NO_X CEMS or parametric monitoring for an existing subpart
GG turbine with low annual utilization (< 1500 hours per year). For a
small baseload turbine, an existing quarterly stack testing requirement
would be an appropriate CEMS or parametric monitoring alternative.
Four commenters stated that the proposed revisions would wrongly
impose significant new requirements for ongoing NO_X
compliance monitoring on mid-range stationary gas turbines and turbines
in natural gas transmission. One commenter gathered over 100 permits,
including construction and title V permits, for turbines subject to the
NSPS. Examination of the gathered permits showed that continuous
monitoring of emissions or parameters has typically not been required.
The commenters expressed opposition to the provisions proposed in Sec.
60.334(c), which they believed fail to address existing mid-range
turbines subject to the NSPS because the vast majority of these
turbines have neither CEMS nor an EPA-approved petition for alternative
monitoring. Even natural gas transmission turbines with emission limits
dramatically lower than the current NSPS limits are not typically
required to install CEMS. Additionally, lean premix turbines have
little possibility of exceeding the NSPS emission limit as it currently
stands. The commenters requested that EPA revise Sec. 60.334(c) to
clearly state that monitoring requirements included in existing permits
should not be revised as a result of this rulemaking. The commenters
also did not support the provisions proposed in Sec. 60.334(e) and (f)
because the commenters believed the provisions would impose significant
new regulatory requirements on new NSPS turbines in natural gas
transmission service and other mid-range units. In addition, one
commenter stated that in the memo in the docket, EPA ignored the costs
for the significant new requirements which would be imposed, since most
of the natural gas transmission and other mid-range units do not
currently have CEMS installed. Therefore, in their opinion, EPA has
failed to estimate the true impacts of the final rule, including the
impacts related to increased monitoring, recordkeeping and reporting
requirements for their industry. The commenters recommended that EPA
write Sec. 60.334(e) and (f) so that they do not impose CEMS or
continuous parameter monitoring requirements on owner/operators that
are not otherwise required to use CEMS or continuous parametric
monitoring, and to consider the current Agency approved NO_X
compliance monitoring techniques that are used by the natural gas
transmission industry for NSPS turbines as alternatives to the
continuous monitoring provisions included in part 75.
Two commenters stated the EPA should not rely on the May 31, 1994
memorandum from John Rasnic (EPA Applicability Determinations Index,
Control No. 9700124) regarding compliance monitoring for turbines that
use technology other than water injection as the basis for the proposed
subpart GG revisions. One commenter requested that the 1994 memorandum
be formally withdrawn by the agency.
Two commenters suggested that if EPA intends to impose new
monitoring requirements for NSPS turbines, EPA should issue a new
proposal with that intent expressly stated. One commenter further
stated that the proposal should include the full range of compliance
monitoring for natural gas combustion turbines, as currently approved
by EPA in existing permits for NSPS turbines, and should be performed
in conjunction with the revisions of the NSPS emission standards.
Response: We have clarified in the preamble that nothing in the
final rule amendments is intended to impose new requirements for
turbines constructed between 1977 and the effective date of the final
rule amendments. Instead, we have described a number of acceptable
continuous compliance methodologies (e.g., the use of CEMS) for these
units. We have added language to the preamble and rule which clarifies
that continuous compliance methodologies already approved by EPA or by
the local permitting authority are still valid. We do not agree that
these revisions would impose new requirements for these turbines. We
have ensured that the regulatory language is clear with respect to the
use of CEMS as an option, and also made sure that any previously
approved methods are still valid. Hence, for existing turbines covered
under subpart GG of 40 CFR part 60, there are no compliance costs
associated with these amendments.
Comment: One commenter requested that EPA provide the option of
monitoring either O₂ or carbon dioxide (CO₂) as a
diluent when using a NO_X CEMS in Sec. 60.334(b), in the
interest of consistency with 40 CFR part 75.
Response: We agree that it is acceptable to make the required
dilution correction with data from a CO₂ monitor. In the
final rule, Sec. 60.334(b) has been revised to include the
CO₂ correction procedure from Method 20. The CO₂
readings must be converted to equivalent O₂ using equations
F-14a or F-14b in 40 CFR part 75, appendix F.
Comment: One commenter requested that EPA clarify whether the
revised subpart GG, 40 CFR part 60, allows application of the 40 CFR
part 75 O₂ (or CO₂) Diluent Cap provisions. This

[[Page 41352]]

provision allows substitution of an O₂ value of 19 percent
for any hour where O₂ is measured at levels greater than 19
percent.
Response: We agree that it is acceptable to provide a diluent cap
procedure for reducing CEMS data. This comment has been incorporated.
Section 60.334(b)(3)(i) of the final rule allows the diluent cap value
of 19.0 percent O₂ to be used to calculate the
NO_X emissions whenever the quality-assured hourly
O₂ concentration measured by the O₂ monitor (or
calculated from a CO₂ monitor reading) is greater than 19.0
percent O₂. No alternative petition will be required.
Comment: One commenter stated that EPA should amend the monitoring
provisions of Sec. 60.334(a) to clarify that monitoring applies only
to those turbines that must use water or steam injection to control
NO_X emissions ``to comply with the NO_X standards
under Sec. 60.332(a).'' The commenter noted that some turbines may be
able to comply with the subpart GG, 40 CFR part 60, NO_X
standard uncontrolled, but need water or steam injection to comply with
a more stringent NO_X standard.
Response: We do not agree with the commenter's suggested
clarification that the monitoring requirements should apply only to
turbines that use steam or water injection to control NO_X
emissions to comply with the NO_X standards under Sec.
60.332(a). Water injection is mentioned in Sec. 60.334(a) because it
was the only emission control technology available for turbines when
subpart GG, 40 CFR part 60, was proposed back in 1977. As we have done
in the past, the use of alternative continuous monitoring methods may
be approved by EPA on a case-by-case basis for turbines that do not use
water injection to control NO_X. Although a turbine may be
able to meet the NO_X emission standard with other control
technologies, continuous monitoring is needed to ensure that the
emission limit is being met at all times.
Comment: One commenter expressed the view that the proposed rule
failed to address the use of NO_X concentration data that
have been ``bias adjusted'' under 40 CFR part 75. The commenter stated
that EPA should acknowledge that sources cannot be required to use bias
adjusted data, as was done in 40 CFR part 60, subpart Da. The commenter
noted that some turbines with emissions significantly lower than their
subpart GG, 40 CFR part 60, limit may prefer to simplify their
reporting by utilizing the same bias adjusted data for subpart GG and
40 CFR part 75 and suggested the EPA make reporting of bias adjusted
data for ``excess emissions'' monitoring optional.
Response: The commenter's suggestion was not incorporated.
Combustion turbines covered under 40 CFR part 75 that use CEMS for
NO_X compliance are required to monitor and report the
NO_X emission rate in pounds per million british thermal
units (lb/MMBTU) on an hourly basis. To achieve this, a NO_X-
diluent CEMS is used to continuously measure the NO_X
concentration (ppm) and either the percent O₂ or percent
CO₂. These measured gas concentrations are used to calculate
the required hourly NO_X emission rates. Under 40 CFR part
75, the relative accuracy test audit (RATA) of a NO_X-diluent
CEMS is performed on a lb/MMBTU basis. If, during the RATA, the
NO_X emission rates calculated from the CEMS data are biased
low with respect to the emission rates derived from the EPA reference
methods, a bias adjustment factor must be applied to the subsequent
hourly NO_X emission rates. Since the bias adjustment factor
is applied to the lb/MMBTU NO_X emission rates and not to the
NO_X ppm values, and since diluent concentration data are
never adjusted for bias under 40 CFR part 75, there is no need to
mention bias-adjusted data in subpart GG of 40 CFR part 60. The subpart
GG emission limits are in units of ppm of NO_X, corrected to
15 percent O₂. Therefore, any 40 CFR part 75 NO_X
concentration or O₂ data used to assess compliance with
these emission limits would not be bias-adjusted.
Comment: One commenter urged EPA to use its PM_2.5
precursor foundation (67 FR 39602, June 10, 2002) to impose an ammonia
(NH₃) CEMS obligation on all gas turbines that utilize SCR
as NO_X control, with quarterly reporting for NO_X
and NH₃ emissions.
Response: Since ammonia is not regulated under subpart GG, 40 CFR
part 60, we do not support adding a continuous monitoring requirement
for ammonia to the NSPS.
Comment: Two commenters stated that some turbines in the gas
transmission industry are diffusion flame combustors, yet are small
(1200 HP, 11 MMBTU/hr). The commenter feels that since the manufacturer
guarantee is 100 ppm while the NSPS emission limit is 150 ppm
NO_X, that a mandatory CEMS requirement is inappropriate and
imposes an unreasonable regulatory burden.
Response: As was stated in the preamble, we did not intend to
impose any new requirements on existing turbines covered subpart GG, 40
CFR part 60, through the promulgation of the final rule. We have
clarified in the final rule that (1) alternatives approved by State and
local agencies under State authority, or delegation of authority from
EPA are also valid, and (2) these amendments do not impose any new
requirements, or require revision of existing permits, but simply
provide several pre-approved options for sources that do not want to
seek case-by-case approval.
Comment: One commenter wanted EPA to explicitly reference appendix
F of 40 CFR part 60, regarding quality assurance procedures for
NO_X CEMS.
Response: Continuous emission monitoring systems are used as an
alternative to water to fuel ratio monitoring, to identify and report
periods of excess emissions, and, therefore, appendix F, procedure 1,
40 CFR part 60, is not mandatory. Section 60.334(b)(4) has been removed.
Comment: Three commenters did not support the proposed changes
presented in Sec. 60.334(f), which address continuous parameter
monitoring as an alternative to CEMS for new turbines that do not use
steam or water injection to control NO_X emissions. The
commenters noted that continuous parameter monitoring is not consistent
with monitoring typically required for mid-range stationary gas
turbines, including turbines used in natural gas transmission service,
and would impose significant new regulatory requirements on these.
Commenters recommended that EPA write the provisions in the final
rulemaking to effect EPA's original intent of codifying the option to
use continuous parameter monitoring, when otherwise required for other
reasons such as 40 CFR part 75, without imposing significant new
requirements on other owners or operators. The commenter also
recommended that EPA explicitly state in the preamble that permitting
authorities, under title V periodic monitoring or other programs, are
not restricted to continuous monitoring of emissions or parameters and
may continue to consider the full range of compliance monitoring
options for gas-fired turbines. One commenter supported EPA's goal of
allowing owners or operators the flexibility to use data from
continuous parameter monitoring already required for other reasons to
demonstrate compliance with the NSPS. However, the commenter does not
support a mandatory requirement for continuous parameter monitoring and
requests that EPA withdraw Sec. 60.334(f) from the direct final and
proposed rules.
In addition, two commenters stated that new lean premix turbines
have little possibility of exceeding the NSPS emission limit as it
currently stands.

[[Page 41353]]

Indeed, verification of lean premix combustion ensures NO_X
emissions at levels far below the current NSPS emission limit. Equally,
information about operation outside of lean premix does not provide
meaningful information about whether a unit has failed to comply with
the current NSPS emission limit.
Response: As was stated in the preamble, we did not intend to
impose any new requirements through the promulgation of the final rule.
We have clarified in the final rule and preamble that the amendments do
not impose any new requirements but simply provide several pre-approved
options for sources that do not want to seek case-by-case approval.
In regard to the comment that new lean premix turbines are able to
comply with the current emission limit with little possibility of
exceeding the standards, we plan to amend the emission limitations in
subpart GG, 40 CFR part 60, as part of an upcoming rulemaking.
Comment: One commenter opposed and requested the removal of the
parameter monitoring plan requirement proposed in Sec. 60.334(g). They
further stated that it does not streamline the differences between
subpart GG, 40 CFR part 60, and 40 CFR part 75 appendix E requirements.
According to the commenter, appendix E adequately addressed this issue.
One commenter requested that the provisions in Sec. 60.334(g), which
address the use of performance test data to establish acceptable
parameter ranges, be written to provide the opportunity for owners and
operators to establish and/or adjust operating parameter limitations
based on performance tests, engineering analysis, design
specifications, manufacturer recommendations or other applicable
information, such as a performance test on a similar unit. Since gas
transmission units are load following, it may not be possible to
operate at specific load conditions at the predetermined time scheduled
for the performance test, and maximum and minimum load condition
emissions may not be seen during the performance test. A similar unit,
however, can exhibit representative emissions for developing parameter
limitations.
Response: The requirement to develop and maintain a parameter
monitoring plan has been retained in the final rule. For units that use
continuous parameter monitoring to assess compliance with the emission
limits under subpart GG, 40 CFR part 60, it is essential for the owner
or operator to clearly identify the monitored parameters and their
acceptable ranges, and to provide the technical basis for selecting
those parameters and ranges. Section 60.334(g) of the final rule allows
the owner or operator to supplement the parametric data recorded at the
time of the initial performance test with other types of information,
in order to establish the appropriate parametric ranges and values.
In response to the comment about units under appendix E, 40 CFR
part 75, Sec. 60.334(f) and (g) of the final rule make it clear that
if the owner or operator performs the parametric monitoring described
in section 2.3 of appendix E, 40 CFR part 75, and maintains the quality
assurance (QA) plan described in section 1.3.6 of 40 CFR part 75,
appendix B, this will satisfy the requirements of subpart GG of 40 CFR
part 60. For the sake of completeness, for low mass emissions (LME)
units, the final rule also allows the owner or operator to use the QA
plan described in Sec. 75.19(e)(5) to satisfy the parameter monitoring
plan requirements of subpart GG.
Comment: Two commenters stated that continuous parameter monitoring
is not appropriate for new diffusion flame turbines subject to NSPS.
Some models of diffusion flame combustors are installed for the natural
gas industry for which there are no predictive emission monitoring
systems available. Development of one would impose an unreasonable
burden on the industry.
Response: Predictive emission monitoring systems (PEMS), are very
different from the parameter monitoring option that we have added to
the final rule. Continuous parameter monitoring refers to the
monitoring of operating conditions or parameters, such as turbine
exhaust temperature, compressor discharge pressure, or any others which
may be indicative of the unit's NO_X formation
characteristics. Predictive emission monitoring systems, on the other
hand, predict actual emission rates or concentrations from operating
parameters that affect NO_X formation. Parameter monitoring
oversees operating parameter boundaries, while PEMS measure emission
rates or concentrations. Adding the option to continuously monitor
parameters that are indicative of the unit's NO_X formation
characteristics would not impose an unreasonable burden on the
industry. No changes have been made from the proposed rule to the final
rule to address this comment.
Comment: One commenter opposed the 4-hour averaging period to
determine compliance. The commenter stated that EPA should base
averaging times on the stated permit conditions of a Prevention of
Significant Deterioration/New Source Review (PSD/NSR) permit issued by
the permitting authority and that subpart GG, 40 CFR part 60, should
remain silent on this issue other than the time it takes to conduct the
required compliance stack testing.
Response: We do not agree with the commenter. The 4-hour averaging
period has been retained in the final rule. The commenter is incorrect
in asserting that subpart GG, 40 CFR part 60, should be silent on the
issue of the averaging period for excess emission reporting. Each NSPS
subpart that requires excess emission monitoring and reporting with
respect to a particular emission limit must specify an averaging
period. If a subpart GG turbine is subject to another more stringent
NO_X emission limit with a different averaging period than
subpart GG (e.g. a permit limit), and if the unit's operating permit
requires excess emission reporting with respect to that limit, then two
separate excess emission reports must be filed, i.e., one to satisfy
subpart GG requirements and the other to meet the permit requirement.
Comment: One commenter did not believe that EPA's attempt to
distinguish between ``excess emissions'' and ``deviations'' is
necessary since neither are violations under subpart GG, 40 CFR part
60. The commenter was also concerned that the choice of the term
``deviation'' could cause confusion in the context of title V permits
and State Implementation Plans (SIP) and suggested the EPA either
continue to use the term ``excess emissions'' for all reported
parameters under subpart GG, or follow the terminology adopted in the
Compliance Assurance Monitoring rule at 40 CFR part 64, which refers to
parameter exceedances as ``excursions.''
Response: We agree with the commenter that it is not necessary to
distinguish between ``deviations'' and ``excess emissions.'' Both terms
represent an averaging period during which a monitored parameter
exceeds the limit specified in the final rule. Therefore, use of the
term ``deviation'' in addition to ``excess emissions'' would be
redundant. The final rule does not use the term ``deviation.''
Comment: One commenter requested clarification on Sec.
60.334(j)(2), which says that periods of excess emissions and monitor
downtime end on the date and hour of the next valid sample. The
commenter stated that EPA should clarify that the period of excess
emissions and/or monitor downtime from the start date to the next valid
sample includes only unit operating hours.

[[Page 41354]]

Another commenter requested that the 4-hour rolling averaging
period for NO_X emissions extend backward three operating
hours, not three quality assured operating hours. The commenter noted
that the standard CEMS vendor software is configured to look back a
fixed number of calendar or on-line hours, but not quality assured
hours.
Response: We agree with both commenters, and have written the final
rule accordingly. ``Quality assured'' has been removed when used in
reference to the rolling averaging period.
Comment: Two commenters requested clarification on the issue of
compliance during startup and shutdown. One commenter asked whether
startup and shutdown hours can be excluded from the 4-hour
NO_X CEMS rolling averages used for compliance determination.
The commenter also asked how site specific startup and shutdown periods
should be established and whether the site can simply use
manufacturer's recommended durations. One commenter stated that EPA
should modify Sec. 60.334(j)(1)(iii)(A) to add language clarifying
that the average excludes emissions from startup, shutdown, and
malfunctions.
Two commenters remarked that the requirement in Sec.
60.334(j)(1)(i)(A) that ``any unit operating hour in which no water or
steam is injected into the turbine shall also be considered a
deviation'' does not appear to exempt startup or shutdown transients.
One commenter said that any gas turbine equipped with steam or water
injection for NO_X control would always have a deviation
during startup and shutdown transients. According to the commenter,
steam or water injection is usually initiated between 20 to 50 percent
of base load during startup and is likewise discontinued during the
shutdown transient. One commenter recommended revising the wording of
the last sentence of the section to read as follows: ``Any unit
operating hour in which no water or steam is injected into the turbine
shall also be considered a deviation for purposes of reporting periods
of startup, shutdown, and malfunction.''
Response: In response to these comments, Sec. 60.334(j) of the
final rule has been written to clearly state that excess emissions must
be recorded during all periods of unit operation, including startup,
shutdown and malfunction. All excess emissions are reported and
categorized. Note that the final rule does not use the term
``deviation.'' Startup and shutdown are two of those categories. We
recognize that even for well-operated units with efficient
NO_X emission controls, excess emission ``spikes'' during
unit startup and shutdown are inevitable, and malfunctions of emission
controls and process equipment occasionally occur. However, at all
times, including periods of startup, shutdown and malfunction, Sec.
60.11(d) requires affected units to be operated in a manner consistent
with good air pollution control practice for minimizing emissions.
Excess emission data may be used to determine whether a facility's
operation and maintenance procedures are consistent with Sec. 60.11(d).

C. Test Methods and Procedures

Comment: One commenter requested that EPA allow performance tests
to be conducted in the normal operating range of the gas turbine and
allow for testing units that cannot be operated at ``peak load'' due to
process constraints. The commenter suggested that instead of 90 to 100
percent of peak load, the owner or operator could test at the highest
achievable load point if 90 to 100 percent of peak load could not
physically be achieved in practice.
Response: The final rule incorporates the commenter's suggested
revisions to Sec. 60.335(b)(2). It is reasonable to make allowance for
units that are not physically capable of attaining 90-to-100 percent of
peak load.
Comment: One commenter suggested that if the permitted operating
range of a turbine is sufficiently narrow, the required number of load
levels for performance testing should be appropriately reduced. The
commenter suggested that a minimum load level spacing of 20 percent be
established.
Response: The requirement for four points for performance testing
is necessary. The purpose of the data is to establish a water to fuel
ratio. Two points are not enough to establish a statistically relevant
relationship. Thus, we have not made any changes from the proposed rule
to the final rule related to this comment.
Comment: Two commenters noted that the reference in Sec. 60.335(a)
to the procedures in section 6.5.6.3(a) and (c) of 40 CFR part 75,
appendix A, should be changed to section 6.5.6.3 (a) and (b).
Similarly, one commenter requested that the single measurement point
identified in sections 6.5.6(b)(4) and 6.5.6.3(b) of 40 CFR part 75,
appendix A, be added to the final rule. The commenter noted that the
stratification testing procedure for a single measurement point is
identical to the long and short measurement lines and the acceptance
criteria for a single measurement point is more stringent.
Response: We agree with the commenter that measurement at a single
point is appropriate in certain situations. In the interest of
consistency with 40 CFR part 75, we have indicated in the final rule
that data collected following section 6.5.6.1 can be used. Also, we
have written the initial performance test requirements in Sec.
60.335(a) to reflect that this option is available. However, because
recently proposed revisions to Method 7E have more restrictive criteria
at lower concentrations than those in section 6.5.6.3 of 40 CFR part
75, it is not appropriate to allow consistency in this case. Therefore,
we have removed reference to section 6.5.6.3 of 40 CFR part 75 in the
final rule. It is still possible to use the same data and choose the
more restrictive number of sampling locations.
Comment: Two commenters recommended that a subparagraph be added to
Sec. 60.335(a) to clearly distinguish requirements for owners and
operators that opt for using ASTM D6522-00 or EPA Method 7E instead of
Method 20. One commenter suggested that the following should be
appended to paragraph (a): ``Other acceptable alternative reference
methods and procedures are given in paragraph (c) of this section.''
The commenters noted that much of the new language EPA has added to
the test methods and procedures under Sec. 60.335(a) pertains to RATA
and as these requirements are being applied to performance testing, any
reference to a RATA is inappropriate and should be replaced with
``performance testing.''
Response: We agree with the commenter that requirements for those
opting to use ASTM D6522-00 and/or EPA Method 7E should be clarified.
Section 60.335(a) has been modified accordingly. We also agree that
references to a RATA in Sec. 60.335(a) should be deleted and replaced
with ``performance testing'' and have written the final rule accordingly.
Comment: Two commenters requested that EPA revise Sec. 60.335(a),
which specifies that owners or operators choosing to use EPA Methods 7E
and 3A (or 3) for NO_X performance testing must perform a
stratification test for NO_X and diluent under 40 CFR part
75, appendix A, section 6.5.6.1(a)-(e) in order to determine if
subsequent RATA testing will occur along a short or long reference
method measurement line. One commenter appreciated EPA's proposal to
add the option of using a short measurement line, but did not
understand why a source that chooses to use the long reference
measurement line would need to perform the stratification

[[Page 41355]]

test. One commenter stated that if a source agrees to use the most
stringent options (i.e., the long measurement line), it would seem
unnecessary to require a stratification check.
Response: Section 60.335(a) applies to a performance test, not a
RATA. We agree that if a source provides initial documentation that
stratification does not exist, it is appropriate to have a reduced
number of sampling points. We also agree that a source can skip the
stratification test and default to using a multi-hole probe, and Sec.
60.335 has been modified accordingly. However, because it is possible
to have spatial stratification due to several reasons such as ammonia
injection that would not be accounted for with the long measurement
line, we are requiring documentation that stratification does not
exist. We have also indicated that the use of data following section
6.5.6.1 of 40 CFR part 75 can be used. In addition, we have reserved a
paragraph in Sec. 60.335(a)(5)(i)(A) that will give the option of
using stratification testing protocols that were proposed for Methods
7E and 3A in a separate Federal Register action.

D. ISO Correction

Comment: Two commenters recommended the removal of the ISO
correction calculation. According to one commenter, the calculation is
not practical for the modern turbine, and incorporation of the ISO
correction factor within a CEMS requires burdensome administrative
changes and unnecessary certification. As an alternative to removal of
the ISO correction calculation, the commenter expressed support for
making the ISO correction optional for specific gas turbines.
Another commenter recommended that EPA harmonize subpart GG, 40 CFR
part 60, with 40 CFR part 75 monitoring requirements, eliminating any
requirement to correct to ISO conditions, instead correcting to 15
percent O₂. The commenter also said that EPA should
recognize the use of water injection as an add-on emission control
device. The commenter noted that many lean premix units operate in
limited use diffusion flame mode with water injection for emissions
control and recommended that EPA recognize these dual-fuel units as
lean premix where the primary fuel is natural gas combusted in lean
premix mode. Further, they suggested that EPA exempt from ISO
correction units that employ water injection when monitored in
accordance with 40 CFR part 75 requirements. Similarly, one commenter
recommended that diffusion flame units using water injection to control
NO_X be exempt from the ISO data correction. Their rationale
is that water injection cools the flame temperature to a level where
NO_X is no longer primarily produced by thermal processes
(much like lean premix, where the majority of NO_X is not
produced thermally).
One commenter suggested that any turbine equipped with a
NO_X CEMS be provided the option of not applying the ISO
correction, irrespective of its design or configuration.
One commenter observed that the use of the ISO correction equation
has no technical basis for gas turbines with lean premix combustors or
for diffusion flame combustors with water or steam injection and
NO_X levels significantly below the subpart GG, 40 CFR part
60, levels of 75 ppm.
Response: No adequate rationale was provided for exempting all
turbines from the ISO correction factor. The ISO correction factor was
initially developed for diffusion flame units, and no rationale has
been provided for making it optional for these units. The ISO
correction factor continues to be appropriate for diffusion flame units
and water or steam injected units. The need for the ISO correction
factor will continue as we begin the process of revising the emission
limits in subpart GG, 40 CFR part 60, in the near future. We have also
clarified in the final rule that when a unit is capable of using both
lean premix and diffusion flame modes, it is considered a lean premix
stationary combustion turbine when it is in the lean premix mode, and
it is considered a diffusion flame stationary combustion turbine when
it is in the diffusion flame mode.
Comment: Two commenters recommended that EPA remove the requirement
to record ambient conditions when operating a turbine. One commenter
stated that this requirement is burdensome and unnecessary and adds an
administrative requirement that has no bearing on the environment. One
commenter stated that for turbine units that are exempt from applying
the ISO correction or which apply worst case ambient conditions to make
the ISO corrections, the reporting of ambient conditions is unnecessary
and represents a significant burden, since they are not collecting this
data on-site.
Response: The ambient condition data is not used for any purpose
other than the ISO correction. Therefore, we agree that the requirement
in the proposed Sec. 60.334(j)(1)(i)(C) and (iii)(C) to report the
ambient conditions is unnecessary for those turbines for which the ISO
correction is optional under Sec. 60.335(b)(1). Also, reporting of
ambient conditions is not necessary if an owner or operator chooses to
calculate and apply a worst case ISO correction factor as specified in
Sec. 60.334(b)(3)(ii). Reporting of ambient conditions is still
necessary for turbines that are required to use the ISO correction
factor and do not opt to use a worst case ISO correction factor. We
have written the final rule accordingly.

E. Emission Standards

Comment: A few commenters suggested revising the emission limits
for sulfur and nitrogen in subpart GG, 40 CFR part 60.
Response: We will address emission limits in a future rulemaking
amending subpart GG. We have not amended the emission limitations at
this time.

F. Duct Burners

Comment: One commenter expressed the opinion that the option to
measure gas turbine NO_X emissions in the exhaust stream
after the duct burner rather than directly after the turbine is not
viable as written because it does not account for the additional
NO_X contribution from the duct burner. The commenter stated
that the final rule should be written to provide for the duct burner
NO_X contribution.
Response: The purpose of the final rule amendment was to allow
owners and operators the flexibility of making one measurement
downstream of the duct burner since many turbines are able to comply
with the NO_X limit even with the potential NO_X
contribution resulting from the duct burner. Accounting for the
NO_X contribution from the duct burner would require two
NO_X measurements, which clearly defeats the purpose of the
amendment. Furthermore, owners and operators still have the option of
simply measuring NO_X emissions in the turbine exhaust, prior
to the duct burner. For these reasons, we disagree with the commenter
and have not made any changes from the proposed rule to the final rule
with respect to this provision.

IV. Environmental and Economic Impacts

The final rule amendments will not have any significant economic or
environmental impacts. The amendments have been written 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

[[Page 41356]]

harmonizing with the requirements of 40 CFR part 75, since many gas
turbines are subject to it as well as subpart GG of 40 CFR part 60.

V. 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.
It has been determined that the final rule is not a ``significant
regulatory action'' under the terms of Executive Order 12866 and is
therefore not subject to EO 12866 review.

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 amendments contain no changes to the information collection
requirements of the current NSPS that would increase the burden to
sources, and the currently approved OMB information collection requests
are still in force for the amended rule. Some amendments in the final
rule, such as allowing the use of CEMS to measure NO_X
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 amendments, 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 Analysis

EPA has determined that it is not necessary to prepare a regulatory
flexibility analysis in connection with the final rule.
For purposes of assessing the impacts of the 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 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 final rule on small
entities, EPA has concluded that this action will not have a
significant economic impact on a substantial number of small entities.
In determining whether a rule has a significant economic impact on a
substantial number of small entities, the impact of concern is any
significant adverse economic impact on small entities, since the
primary purpose of the regulatory flexibility analysis is to identify
and address regulatory alternatives ``which minimize any significant
economic impact of the proposed rule on small entities.'' 5 U.S.C.
Sec. Sec. 603 and 604. Thus, an agency may conclude that a rule will
not have a significant economic impact on a substantial number of small
entities if the rule relieves regulatory burden, or otherwise has a
positive economic effect on all of the small entities subject to the
rule. Our conclusion that today's final rule will relieve regulatory
burden on small entities 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
current combustion turbines is a good approximation of the mix of
turbines that will be installed and affected by the 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

[[Page 41357]]

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 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 final rule amendments are not
subject to the requirements of section 203 of the UMRA.

E. Executive Order 13132: Federalism

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

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

Executive Order 13175 (59 FR 22951, November 6, 2000) requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by tribal officials in the development of regulatory policies
that have tribal implications.'' ``Policies that have tribal
implications'' is defined in the Executive Order to include regulations
that have ``substantial direct effects on one or more Indian tribes, on
the relationship between the Federal government and the Indian tribes,
or on the distribution of power and responsibilities between the
Federal government and Indian tribes.''
The final rule does not have tribal implications. It will not have
substantial direct effects on tribal governments, on the relationship
between the Federal government and Indian tribes, or on the
distribution of power and responsibilities between the Federal
government and Indian tribes, as specified in Executive Order 13175. We
do not know of any stationary gas turbines owned or operated by Indian
tribal governments. However, if there are any, the effect of the final
rule on communities of tribal governments would not be unique or
disproportionate to the effect on other communities. Thus, Executive
Order 13175 does not apply to the final rule.

G. Executive Order 13045: Protection of Children From Environmental
Health 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 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 final rule is not subject to Executive Order 13211 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 (Pub. L. 104-113; 15 U.S.C. 272 note) directs EPA
to use voluntary consensus standards in their regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, business practices) developed or adopted by one or
more voluntary consensus bodies. The NTTAA directs EPA to provide
Congress, through annual reports to OMB, with explanations when an
agency does not use available and applicable voluntary consensus standards.
These final rule amendments involve technical standards. The EPA
cites the following methods in the final rule amendments: EPA Methods
1, 3, 3A, 7E, and 20 of 40 CFR part 60, appendix A; and PS 2 and 3 of
40 CFR part 60, appendix B. In addition, these final rule amendments
cite the following standards that are also incorporated by reference
(IBR) in 40 CFR part 60, section 17: ASTM D129-00, ASTM D1072-80 or -90
(Reapproved 1999), ASTM D1266-98, ASTM D1552-01, ASTM D2597-94
(Reapproved 1999), ASTM D2622-98, ASTM D3246-81 or -92 or -96, ASTM
D4084-82 or -94, 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 these EPA methods/
performance specifications. No applicable voluntary consensus standards
were identified for PS 3. The search and review results have been
documented and are placed in the docket (OAR-2002-0053) for the final
rule amendments.

[[Page 41358]]

One voluntary consensus standard was identified as an acceptable
alternative to the EPA methods specified in the final rule amendments.
The 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,'' is cited in the final rule amendments as an
acceptable alternative to EPA Methods 3A, 7E, and 20 for identifying
nitrogen oxide and oxygen concentration when the fuel is natural gas.
This standard, ASTM D6522-00, has been also IBR in 40 CFR part 60,
section 17.
In addition to the voluntary consensus standards EPA uses in the
final rule amendments, the search for emissions measurement procedures
identified eight other voluntary consensus standards. The EPA
determined that seven of these eight standards identified for measuring
air emissions or surrogates subject to emission standards in the final
rule amendments were impractical alternatives to EPA test methods/
performance specifications for the purposes of these final rule
amendments. Therefore, the EPA does not intend to adopt these
standards. See the docket for the reasons for the determinations of
these seven methods.
Sections 60.334 and 60.335 of the final rule amendments to subpart
GG, 40 CFR part 60, discuss the EPA testing methods, performance
specification, and procedures required. Under Sec. Sec. 63.7(f) and
63.8(f) of subpart A of the General Provisions, a source may apply to
EPA for permission to use alternative test methods or alternative
monitoring requirements in place of any of 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 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 final rule in the Federal Register. The 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.

Dated: June 24, 2004.
Michael O. Leavitt,
Administrator.

? 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]

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

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

Subpart A--[AMENDED]

? 2. Section 60.17 is amended by:
? a. Removing and reserving paragraph (a)(38);
? b. Revising paragraph (a) introductory text;
? c. Revising paragraph (a)(8);
? d. Revising paragraph (a)(15);
? e. Revising paragraph (a)(18);
? f. Revising paragraph (a)(20);
? g. Revising paragraph (a)(33);
? h. Revising paragraph (a)(43);
? i. Revising paragraph (a)(50);
? j. Adding paragraphs (a)(65) through (a)(75); and
? 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

[[Page 41359]]

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, PO 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).

Subpart GG--[Amended]

? 3. Section 60.331 is amended by adding paragraphs (s) through (y) 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) Excess emissions means a specified averaging period over which
either:
(1) The NO_X emissions are higher than the applicable
emission limit in Sec. 60.332;
(2) The total sulfur content of the fuel being combusted in the
affected facility exceeds the limit specified in Sec. 60.333; or
(3) The recorded value of a particular monitored parameter is
outside the acceptable range specified in the parameter monitoring plan
for the affected unit.
(u) 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. Equivalents of this in other units are as
follows: 0.068 weight percent total sulfur, 680 parts per million by
weight (ppmw) total sulfur, and 338 parts per million by volume (ppmv)
at 20 degrees Celsius total sulfur. 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 British thermal units (Btu)
per standard cubic foot. Natural gas does not include the following
gaseous fuels: landfill gas, digester gas, refinery gas, sour gas,
blast furnace gas, coal-derived gas, producer gas, coke oven gas, or
any gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value.
(v) 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.
(w) Lean premix stationary combustion turbine means any stationary
combustion turbine where the air and fuel are thoroughly mixed to form
a lean mixture for combustion in the combustor. Mixing may occur before
or in the combustion chamber. A unit which is capable of operating in
both lean premix and diffusion flame modes is considered a lean premix
stationary combustion turbine when it is in the lean premix mode, and
it is considered a diffusion flame stationary combustion turbine when
it is in the diffusion flame mode.
(x) 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. A unit
which is capable of operating in both lean premix and diffusion flame
modes is considered a lean premix stationary combustion turbine when it
is in the lean premix mode, and it is considered a diffusion flame
stationary combustion turbine when it is in the diffusion flame mode.
(y) Unit operating day means a 24-hour period between 12:00
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.

? 4. Section 60.332 is amended by:
? a. Revising the terms to the equations in paragraphs (a)(1) through (2);
? b. Redesignating paragraph (a)(3) as (a)(4);
? c. Revising newly designated paragraph (a)(4); and
? 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 Sec.
60.335(b)(1)) NO_X 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 = NO_X emission allowance for fuel-bound nitrogen as
defined in paragraph (a)(4) of this section.

(2) * * *

Where:

STD = allowable ISO corrected (if required as given in Sec.
60.335(b)(1)) NO_X emission concentration (percent by volume
at 15 percent oxygen and on a dry basis),
Y = manufacturer's rated heat rate at manufacturer's rated peak 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 = NO_X emission allowance for fuel-bound nitrogen as
defined in paragraph (a)(4) of this section.
(3) The use of F in paragraphs (a)(1) and (2) of this seciton is
optional. That

[[Page 41360]]

is, the owner or operator may choose to apply a NO_X
allowance for fuel-bound nitrogen and determine the appropriate F-value
in accordance with paragraph (a)(4) of this section or may accept an F-
value of zero.
(4) If the owner or operator elects to apply a NO_X
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
0.015 < N< = 0.1....................... 0.04(N)
0.1 < N < = 0.25....................... 0.004+0.0067(N-0.1)
N > 0.25.............................. 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.
* * * * *

? 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).

? 6. Section 60.334 is amended by:
? a. Revising paragraphs (a) and (b);
? b. Redesignating paragraph (c) as paragraph (j);
?
c. Adding a new paragraph (c);
? d. Adding paragraphs (d) through (i);
? e. Revising newly designated paragraph (j) introductory text, (j)(1)
and (j)(2); and
? 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
NO_X emissions shall install, calibrate, maintain and operate
a continuous monitoring system to monitor and record the fuel
consumption and the ratio of water or steam to fuel being fired in the
turbine.
(b) The owner or operator of any stationary gas turbine that
commenced construction, reconstruction or modification after October 3,
1977, but before July 8, 2004, and which uses water or steam injection
to control NO_X 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
NO_X and O₂ monitors. As an alternative, a
CO₂ monitor may be used to adjust the measured
NO_X concentrations to 15 percent O₂ by either
converting the CO₂ hourly averages to equivalent
O₂ concentrations using Equation F-14a or F-14b in appendix
F to part 75 of this chapter and making the adjustments to 15 percent
O₂, or by using the CO₂ readings directly to make
the adjustments, as described in Method 20. If the option to use a CEMS
is chosen, the CEMS shall be installed, certified, maintained and
operated 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, except the 7-day
calibration drift is based on unit operating days, not calendar days.
Appendix F, Procedure 1 is not required. The relative accuracy test
audit (RATA) of the NO_X and diluent 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 NO_X) and a percent O₂
basis for oxygen; or
(ii) On a ppm at 15 percent O₂ basis; or
(iii) On a ppm basis (for NO_X) and a percent
CO₂ basis (for a CO₂ monitor that uses the
procedures in Method 20 to correct the NO_X data to 15
percent O₂).
(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
NO_X and diluent, the data acquisition and handling system
must calculate and record the hourly NO_X emissions in the
units of the applicable NO_X emission standard under Sec.
60.332(a), i.e., percent NO_X 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)). For any hour in which the hourly average
O₂ concentration exceeds 19.0 percent O₂, a
diluent cap value of 19.0 percent O₂ may be used in the
emission calculations.
(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 (T_a), and minimum combustor
inlet absolute pressure (P_o) into the ISO correction equation.
(iii) If the owner or operator has installed a NO_X CEMS
to meet the requirements of part 75 of this chapter, and is continuing
to meet the ongoing requirements of part 75 of this chapter, the CEMS
may be used to meet the requirements of this section, except that the
missing data substitution methodology provided for at 40 CFR part 75,
subpart D, is not required 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).
(c) For any turbine that commenced construction, reconstruction or
modification after October 3, 1977, but before July 8, 2004, and which
does not use steam or water injection to control NO_X
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 or local permitting authority approval of a
petition for an alternative procedure of continuously monitoring
compliance with the applicable NO_X emission limit under
Sec. 60.332, that approved procedure may continue to be used, even if
it deviates from paragraph (a) of this section.

[[Page 41361]]

(d) The owner or operator of any new turbine constructed after July
8, 2004, and which uses water or steam injection to control
NO_X 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 NO_X 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 July 8, 2004, and which does not use water or steam
injection to control NO_X emissions may elect to use a
NO_X 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 NO_X
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-
NO_X) combustion mode.
(3) For any turbine that uses SCR to reduce NO_X
emissions, the owner or operator shall continuously monitor appropriate
parameters to verify the proper operation of the emission controls.
(4) For affected units that are also regulated under part 75 of
this chapter, if the owner or operator elects to monitor NO_X
emission rate using the methodology in appendix E to part 75 of this
chapter, or the low mass emissions methodology in Sec. 75.19 of this
chapter, the requirements of this paragraph (f) may be met by
performing the parametric monitoring described in section 2.3 of
appendix E or in Sec. 75.19(c)(1)(iv)(H) of this chapter.
(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 may supplement the performance test data with engineering
analyses, design specifications, manufacturer's recommendations and
other relevant information to define the acceptable parametric ranges
more precisely. 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 NO_X 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). Any supplemental data such as
engineering analyses, design specifications, manufacturer's
recommendations and other relevant information shall be included in the
monitoring plan. For affected units that are also subject to part 75 of
this chapter and that use the low mass emissions methodology in Sec.
75.19 of this chapter or the NO_X emission measurement
methodology in appendix E to part 75, the owner or operator may meet
the requirements of this paragraph by developing and keeping on-site
(or at a central location for unmanned facilities) a quality-assurance
plan, as described in Sec. 75.19 (e)(5) or in section 2.3 of appendix
E and section 1.3.6 of appendix B to part 75 of this chapter.
(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(u), 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 turbine that commenced construction, reconstruction or
modification after October 3, 1977, but before July 8, 2004, and for
which a custom fuel monitoring schedule has previously 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

[[Page 41362]]

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
paragraphs (i)(3)(i)(A) through (D) 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(u)), 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 and monitor downtime,
in accordance with Sec. 60.7(c). Excess emissions shall be reported
for all periods of unit operation, including startup, shutdown and
malfunction. For the purpose of reports required under Sec. 60.7(c),
periods of excess emissions 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) An excess emission 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 an excess emission.
(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 excess emission. You do not
have to report ambient conditions if you opt to use the worst case ISO
correction factor as specified in Sec. 60.334(b)(3)(ii), or if you are
not using the ISO correction equation under the provisions of Sec.
60.335(b)(1).
(ii) If the owner or operator elects to take an emission allowance
for fuel bound nitrogen, then excess emissions and periods of monitor
downtime are as described in paragraphs (j)(1)(ii)(A) and (B) of this
section.
(A) An excess emission shall be the period of time during which the
fuel-bound nitrogen (N) is greater than the value measured during the
performance test required in Sec. 60.8 and used to determine the
allowance. The excess emission 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 NO_X and diluent CEMS:
(A) An hour of excess emissions shall be any unit operating hour in
which the 4-hour rolling average NO_X 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 NO_X
concentration'' is the arithmetic average of the average NO_X
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 unit operating hour average
NO_X concentrations immediately preceding that unit operating
hour.

[[Page 41363]]

(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 NO_X concentration or diluent (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. You do not have to report ambient conditions if you
opt to use the worst case ISO correction factor as specified in Sec.
60.334(b)(3)(ii), or if you are not using the ISO correction equation
under the provisions of Sec. 60.335(b)(1).
(iv) For turbines required under paragraph (f) of this section to
monitor combustion parameters or parameters that document proper
operation of the NO_X emission controls:
(A) An excess emission 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 occurs each unit operating hour
included in the period beginning on the date and hour of any sample for
which the sulfur content of the fuel being fired in the gas turbine
exceeds 0.8 weight percent and ending 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 shall include only unit
operating hours, and 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.

? 7. Section 60.335 is revised to 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
(1) EPA Method 20,
(2) ASTM D6522-00 (incorporated by reference, see Sec. 60.17), or
(3) EPA Method 7E and either EPA Method 3 or 3A in appendix A to
this part, to determine NO_X and diluent concentration.
(4) Sampling traverse points are to be selected following Method 20
or Method 1, (non-particulate procedures) and sampled for equal time
intervals. The sampling shall be performed with a traversing single-
hole probe or, if feasible, with a stationary multi-hole probe that
samples each of the points sequentially. Alternatively, a multi-hole
probe designed and documented to sample equal volumes from each hole
may be used to sample simultaneously at the required points.
(5) Notwithstanding paragraph (a)(4) of this section, the owner or
operator may test at few points than are specified in Method 1 or
Method 20 if the following conditions are met:
(i) You may perform a stratification test for NO_X and
diluent pursuant to
(A) [Reserved]
(B) The procedures specified in section 6.5.6.1(a) through (e)
appendix A to part 75 of this chapter.
(ii) Once the stratification sampling is completed, the owner or
operator may use the following alternative sample point selection
criteria for the performance test:
(A) If each of the individual traverse point NO_X
concentrations, normalized to 15 percent O₂, is within
± 10 percent of the mean normalized concentration for all
traverse points, then you may use 3 points (located either 16.7, 50.0,
and 83.3 percent of the way across the stack or duct, or, for circular
stacks or ducts greater than 2.4 meters (7.8 feet) in diameter, at 0.4,
1.2, and 2.0 meters from the wall). The 3 points shall be located along
the measurement line that exhibited the highest average normalized
NO_X concentration during the stratification test; or
(B) If each of the individual traverse point NO_X
concentrations, normalized to 15 percent O₂, is within
± 5 percent of the mean normalized concentration for all
traverse points, then you may sample at a single point, located at
least 1 meter from the stack wall or at the stack centroid.
(6) 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 mean nitrogen oxides
emission concentration (NO_Xo) corrected to 15 percent
O₂ shall be corrected to ISO standard conditions using the
following equation. Notwithstanding this requirement, use of the ISO
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:

NO_X=(NO_Xo)(P_r/
P_o)0.5 e19 (Ho-0.00633) (288[deg]K/
T_a)1.53

Where:
NO_X = emission concentration of NO_X at 15 percent
O₂ and ISO standard ambient conditions, ppm by volume, dry
basis,
NO_Xo = mean observed NO_X concentration, ppm by
volume, dry basis, at 15 percent O₂,
P_r = reference combustor inlet absolute pressure at 101.3
kilopascals ambient pressure, mm Hg,
P_o = observed combustor inlet absolute pressure at test, mm
Hg,
H_o = observed humidity of ambient air, g H₂O/g air,
e = transcendental constant, 2.718, and
T_a = 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, or at the highest
achievable load point if 90-to-100 percent of peak load cannot be
physically achieved in practice. If the turbine combusts both oil and
gas as primary or backup fuels, separate performance testing is
required for each fuel. Notwithstanding these

[[Page 41364]]

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
NO_X 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 NO_X emission
limit in Sec. 60.332 for the combustion turbine must still be met.
(4) If water or steam injection is used to control NO_X
with no additional post-combustion NO_X 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
NO_X 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
NO_X 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 (or the highest physically achievable) load.
(ii) Use the test data both to demonstrate compliance with the
applicable NO_X 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 NO_X 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) The owner or operator may use the following as alternatives to
the reference methods and procedures specified in this section:
(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.

[FR Doc. 04-14825 Filed 7-7-04; 8:45 am]
BILLING CODE 6560-50-P

Notices For
2009
2008
2007
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2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994

Standards of Performance for Stationary Gas Turbines

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