[Federal Register Volume 69, Number 130 (Thursday, July 8, 2004)]
[Rules and Regulations]
[Pages 41346-41364]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-14825]



[[Page 41345]]

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Part III





Environmental Protection Agency





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40 CFR Part 60



Standards of Performance for Stationary Gas Turbines; Final Rule

  Federal Register / Vol. 69, No. 130 / Thursday, July 8, 2004 / Rules 
and Regulations  

[[Page 41346]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[OAR-2002-0053, FRL-7780-6]
RIN 2060-AK35


Standards of Performance for Stationary Gas Turbines

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 
(NOX) 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 [email protected].

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.epa.gov/edocket/ to view public comments, 
access the index listing of the contents of the official public docket, 
and to access those documents in the public docket that are available 
electronically. Although not all docket materials may be available 
electronically, you may still access any of the publicly available 
docket materials through the docket facility located above. Once in the 
system, select ``search,'' then key in the appropriate docket 
identification number.
    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 
NOX 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 NOX standard. We 
are amending the regulation to allow the use of NOX 
continuous emission monitoring systems (CEMS) to demonstrate 
compliance, as detailed in the following paragraphs.
    Owners or operators of turbines that commenced construction, 
reconstruction, or modification after October 3, 1977, but before July 
8, 2004, and that use water or steam injection to control 
NOX emissions can continue to use the NOX 
monitoring system which is currently being used, or may elect to use a 
NOX CEMS. The CEMS must be installed, operated, and 
maintained according to the appropriate performance specification 
requirements in 40 CFR part 60, appendix B. Alternatively, sources may 
choose to use data from a NOX CEMS that is certified 
according to the requirements of 40 CFR part 75. Any owners or 
operators of turbines constructed, reconstructed, or modified in this 
time period that do not use water or steam injection and that have 
received EPA 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 NOX control, owners/operators can elect 
to use either the existing requirements for continuous water or steam 
to fuel ratio monitoring or may elect to use a CEMS to monitor 
NOX. The CEMS must be installed 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 NOX 
CEMS that is certified according to the requirements of 40 CFR part 75, 
appendix A.
    Owners or operators of new turbines that commence construction 
after July 8, 2004, and do not use water or steam injection to control 
NOX emissions can use a NOX CEMS as an 
alternative to continuously monitoring fuel consumption and water or 
steam to fuel ratio, provided the CEMS is installed 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 NOX CEMS is continuous 
parameter monitoring. If this option is chosen, owners or operators of 
uncontrolled diffusion flame turbines must continuously monitor at 
least four parameters indicative of the unit's NOX formation 
characteristics. For lean premix turbines, continuous monitoring of 
parameters that indicate whether the turbine is operating in the lean 
premixed combustion mode is required. Examples of these parameters may 
include percentage of full load, turbine exhaust temperature, 
combustion reference temperature, compressor discharge pressure, fuel 
and air valve positions, dynamic pressure pulsations, internal guide 
vane position, and flame detection or flame scanner conditions. 
Definitions for diffusion flame turbine

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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 NOX CEMS is chosen, we have 
specified the minimum data requirements. For full operating hours, each 
monitor must complete at least one cycle of operation (including 
sampling, analyzing, and data recording) for each 15-minute quadrant of 
the hour. For partial unit operating hours, one valid data point must 
be obtained for each quadrant of the hour for which the unit is 
operating. 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 NOX emissions as well as the International 
Organization for Standardization (ISO) standard conditions (if 
applicable).
    In lieu of recording the ISO standard conditions, a worst case ISO 
correction factor can be calculated using historical ambient data. For 
the purpose of this calculation, substitute the maximum humidity of 
ambient air (Ho), minimum ambient temperature 
(Ta), and minimum combustor inlet absolute pressure 
(Po) into the ISO correction equation. By using worst case 
parameters in this equation, the owner/operator can ensure compliance 
in all situations without having to continuously monitor temperature, 
humidity and pressure. Several case-by-case determinations performed by 
EPA have accepted this methodology as an alternative to continuous 
monitoring of atmospheric conditions.
    No NOX 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 NOX CEMS, we have 
defined excess emissions as any unit operating hour during which the 4-
hour rolling average NOX concentration exceeds the 
applicable emission limit.
    The 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 
NOX emissions, particularly when solid fuels are fired. 
Combustion turbines typically use natural gas or diesel, which both 
have relatively uniform predictable NOX 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 NOX 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 NOX CEMS as an alternative to 
continuously monitoring fuel consumption and water or steam to fuel 
ratio because the majority of new turbines do not rely on water 
injection for NOX control. Therefore, for those turbines, 
the monitoring originally required by subpart GG, 40 CFR part 60, is 
not appropriate. The use of a NOX CEMS will show compliance 
with the NOX standard of subpart GG over all operating 
ranges. Additionally, many of the units affected by subpart GG are 
already required to install and certify CEMS for NOX under 
other requirements, such as the acid rain monitoring regulation in 40 
CFR part 75, or through conditions in various permit requirements. To 
reduce the burden on these units, we are allowing the use of CEMS units 
that are certified according to the requirements of 40 CFR part 75. The 
40 CFR part 75 testing procedures to certify the CEMS are nearly 
identical to those in 40 CFR part 60, and 40 CFR part 75 has rigorous 
quality assurance and quality control standards. 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 NOX emission standard in 40 CFR 60.332 includes a 
NOX emission allowance for fuel-bound nitrogen. The use of 
this allowance for fuel-bound nitrogen will be optional upon July 8, 
2004. Owners or operators will be able to choose to accept a value of 
zero for the NOX emission allowance. The NOX 
emission limitations in many State permits are much more stringent than 
those of subpart GG 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 NOX standard. We are allowing sources 
that are using steam injection to monitor the ratio of steam to fuel 
and fuel consumption to demonstrate compliance. Steam injection is 
another method of NOX control, and water and steam injection 
are the wet methods usually used. Steam injection monitoring is an 
acceptable type of parametric emission monitoring method.

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

    When subpart GG 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 NOX and diluent concentration during the 
performance test, we are adding EPA Method 7E of 40 CFR part 60, 
appendix A, used in conjunction with EPA Method 3 or 3A of 40 CFR part 
60, appendix A, as an acceptable alternative to EPA Method 20. In 
addition, we are adding ASTM D6522-00 as another alternative to EPA 
Method 20.
    Subpart GG of 40 CFR part 60 previously required the NOX 
initial compliance testing to be conducted at four different loads 
across the unit's operating range. This testing was required because of 
the difficulty in predicting which operating load will represent worst 
case conditions when monitoring operational data. Testing, therefore, 
was done across the operating range to determine the water to fuel 
ratio and fuel consumption needed to maintain NOX compliance 
across the unit's normal operating range. One of the tests was required 
to be conducted at 100 percent of peak load. We are 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 NOX CEMS 
monitoring option. The NOX CEMS will provide realtime data 
on NOX emissions for any given time of operation. This data 
provides credible evidence which can be used to determine the unit's 
compliance status on a continuous basis following the initial test. The 
availability of this continuous information through the use of 
NOX CEMS after the initial performance testing justifies 
testing at a single load

[[Page 41350]]

for the initial compliance testing. We are also clarifying how data 
collected during a relative accuracy test audit (RATA) of the 
NOX CEMS may be used to demonstrate compliance with the 
performance tests required by 40 CFR 60.8. The RATA consists of a 
minimum of nine 21-minute runs using EPA reference test methods, for a 
total of 189 minutes or just over 3 hours. This amount of sampling 
accompanied by sampling at multiple traverse points during a RATA 
provides enough representative emissions data to determine the unit's 
compliance status.
    Finally, a statement has been added to clarify that if the turbine 
combusts both oil and gas, separate performance testing is required for 
each type of fuel combusted by the turbine, except for emergency fuel. 
This is appropriate due to the fact that NOX emissions vary 
by fuel type.

G. Measurement After Duct Burner

    For sources that are combined cycle turbine systems using 
supplemental heat, we have added an option that the turbine 
NOX emissions may be measured after the duct burner rather 
than directly after the turbine. No additional NOX allowance 
is given. A definition for duct burner has also been added to the 
definitions section of the final rule. For combined cycle units, there 
are several concerns with testing and monitoring NOX at the 
turbine outlet. For example, it is questionable whether the turbine 
outlet location is suitable for installation of CEMS. Moreover, due to 
the high temperature and pressure of the turbine exhaust at that 
location, it may be difficult to conduct an EPA Method 20 performance 
test at the turbine outlet of a combined cycle unit. In addition, any 
combined cycle units that are subject to NOX CEMS 
requirements for 40 CFR part 75 or subparts Da and Db of 40 CFR part 60 
will most likely have installed the CEMS after the duct burner, on the 
heat recovery steam generator (HRSG) stack. Another reason to allow 
measurement of NOX emissions after the duct burner is that 
add-on NOX control systems such as selective catalytic 
reduction (SCR) are generally located after the duct burner; turbine 
NOX performance testing should be conducted after the 
NOX control device and would, therefore, include emissions 
from the duct burner.

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

    We have added an option to not use the ISO correction equation for 
the following units: Lean premix combustor turbines, units used in 
association with 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 NOX concentration is 
established at each facility. This is accomplished by simultaneously 
measuring the NOX concentration and using a CMS to monitor 
the water or steam to fuel ratio that achieves that NOX 
level at various turbine loads at the specific facility during a 
performance test. This calibration serves to assure that if the water 
or steam to fuel ratio is maintained above this surrogate value using 
the same CMS, then acceptable NOX concentration levels are 
attained even if the actual numerical value is not correct. Hence, the 
requirement to be accurate within plus or minus 5 percent is not 
necessary.

J. 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 NOX standard in 40 CFR 
60.332(a)(1) to indicate that it is an emission concentration and 
should be ISO corrected (if required); and (3) clarified the 
NOX emission concentration equation in 40 CFR 60.335(b)(1) 
to indicate it is a concentration instead of a rate and that it is on a 
dry basis.

III. 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 NOX emission 
standards.
    One commenter requested that EPA make clear that the choice of 
whether to use a NOX CEMS is entirely at the discretion of 
the source owner or operator, even in those cases where a 
NOX 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 NOX monitoring under 
their current approvals may continue to operate under the provisions of 
their current approvals. The commenter stated that an annual 
NOX stack test could serve as an appropriate alternative to 
a NOX 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 NOX 
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 NOX 
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 NOX 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 
NOX 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 
NOX emissions ``to comply with the NOX 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, NOX 
standard uncontrolled, but need water or steam injection to comply with 
a more stringent NOX 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 NOX 
emissions to comply with the NOX 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 NOX. Although a turbine may be 
able to meet the NOX 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 NOX 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 
NOX compliance are required to monitor and report the 
NOX emission rate in pounds per million british thermal 
units (lb/MMBTU) on an hourly basis. To achieve this, a NOX-
diluent CEMS is used to continuously measure the NOX 
concentration (ppm) and either the percent O2 or percent 
CO2. These measured gas concentrations are used to calculate 
the required hourly NOX emission rates. Under 40 CFR part 
75, the relative accuracy test audit (RATA) of a NOX-diluent 
CEMS is performed on a lb/MMBTU basis. If, during the RATA, the 
NOX 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 NOX emission rates. Since the bias adjustment factor 
is applied to the lb/MMBTU NOX emission rates and not to the 
NOX 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 NOX, corrected to 
15 percent O2. Therefore, any 40 CFR part 75 NOX 
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 PM2.5 
precursor foundation (67 FR 39602, June 10, 2002) to impose an ammonia 
(NH3) CEMS obligation on all gas turbines that utilize SCR 
as NOX control, with quarterly reporting for NOX 
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 
NOX, 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 
NOX 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 NOX 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 NOX 
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 NOX formation 
characteristics. Predictive emission monitoring systems, on the other 
hand, predict actual emission rates or concentrations from operating 
parameters that affect NOX 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 NOX 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 
NOX 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 NOX 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 
NOX 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 NOX 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 
NOX emission controls, excess emission ``spikes'' during 
unit startup and shutdown are inevitable, and malfunctions of emission 
controls and process equipment occasionally occur. However, at all 
times, including periods of startup, shutdown and malfunction, 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 NOX performance testing must perform a 
stratification test for NOX 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 
NOX be exempt from the ISO data correction. Their rationale 
is that water injection cools the flame temperature to a level where 
NOX is no longer primarily produced by thermal processes 
(much like lean premix, where the majority of NOX is not 
produced thermally).
    One commenter suggested that any turbine equipped with a 
NOX 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 
NOX 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 NOX 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 
NOX contribution from the duct burner. The commenter stated 
that the final rule should be written to provide for the duct burner 
NOX 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 NOX limit even with the potential NOX 
contribution resulting from the duct burner. Accounting for the 
NOX contribution from the duct burner would require two 
NOX measurements, which clearly defeats the purpose of the 
amendment. Furthermore, owners and operators still have the option of 
simply measuring NOX 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 NOX 
emissions, are provided as an option to sources, and should reduce 
burden to those sources who already have a CEMS in place for other 
regulatory reasons, such as the Acid Rain requirements in 40 CFR part 
75. Other 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 (65 FR 67249, November 6, 2000) requires EPA 
to develop an accountable process to ensure ``meaningful and timely 
input by tribal officials in the development of regulatory policies 
that have tribal implications.'' ``Policies that have tribal 
implications'' is defined in the Executive Order to include regulations 
that have ``substantial direct effects on one or more Indian tribes, on 
the relationship between the Federal government and the Indian tribes, 
or on the distribution of power and responsibilities between the 
Federal government and Indian tribes.''
    The final rule does not have tribal implications. It will not have 
substantial direct effects on tribal governments, on the relationship 
between the Federal government and Indian tribes, or on the 
distribution of power and responsibilities between the Federal 
government and Indian tribes, as specified in Executive Order 13175. We 
do not know of any stationary 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.

0
For the reasons stated in the preamble, title 40, chapter I, part 60, 
of the Code of Federal Regulations is amended to read as follows:

PART 60--[Amended]

0
1. The authority citation for part 60 continues to read as follows:

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

Subpart A--[AMENDED]

0
2. Section 60.17 is amended by:
0
a. Removing and reserving paragraph (a)(38);
0
b. Revising paragraph (a) introductory text;
0
c. Revising paragraph (a)(8);
0
d. Revising paragraph (a)(15);
0
e. Revising paragraph (a)(18);
0
f. Revising paragraph (a)(20);
0
g. Revising paragraph (a)(33);
0
h. Revising paragraph (a)(43);
0
i. Revising paragraph (a)(50);
0
j. Adding paragraphs (a)(65) through (a)(75); and
0
k. Adding paragraph (m).
    The revisions and additions read as follows:


Sec.  60.17  Incorporation by Reference

* * * * *
    (a) The following materials are available for purchase from at 
least one of the following addresses: American Society for Testing and 
Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West 
Conshohocken, PA 19428-2959; or ProQuest, 300 North Zeeb Road, Ann 
Arbor, MI 48106.
* * * * *
    (8) ASTM D129-64, 78, 95, 00, Standard Test Method for Sulfur in 
Petroleum Products (General Bomb Method), IBR approved for appendix A: 
Method 19, 12.5.2.2.3; Sec. Sec.  60.106(j)(2) and 60.335(b)(10)(i).
* * * * *
    (15) ASTM D1072-80, 90 (Reapproved 1994), Standard Test Method for 
Total Sulfur in Fuel Gases, IBR approved for Sec.  60.335(b)(10)(ii).
* * * * *
    (18) ASTM D1266-87, 91, 98, Standard Test Method for Sulfur in 
Petroleum Products (Lamp Method), IBR approved for Sec. Sec.  
60.106(j)(2) and 60.335(b)(10)(i).
* * * * *
    (20) ASTM D1552-83, 95, 01, Standard Test Method for Sulfur in 
Petroleum Products (High-Temperature Method), IBR approved for appendix 
A: Method 19, Section 12.5.2.2.3; Sec. Sec.  60.106(j)(2) and 
60.335(b)(10)(i).
* * * * *
    (33) ASTM D2622-87, 94, 98, Standard Test Method for Sulfur in 
Petroleum Products by Wavelength Dispersive X-Ray Fluorescence 
Spectrometry,'' IBR approved for Sec. Sec.  60.106(j)(2) and 
60.335(b)(10)(i).
* * * * *
    (43) ASTM D3246-81, 92, 96, Standard Test Method for Sulfur in 
Petroleum Gas by Oxidative Microcoulometry, IBR approved for Sec.  
60.335(b)(10)(ii).
* * * * *
    (50) ASTM D4084-82, 94, Standard Test Method for Analysis of 
Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), 
IBR approved for Sec.  60.334(h)(1).
* * * * *
    (65) ASTM D2597-94 (Reapproved 1999), Standard Test Method for 
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing 
Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for 
Sec.  60.335(b)(9)(i).
    (66) ASTM D4294-02, Standard Test Method for Sulfur in Petroleum 
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence 
Spectrometry, IBR approved for Sec.  60.335(b)(10)(i).
    (67) ASTM D4468-85 (Reapproved 2000), Standard Test Method for 
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric 
Colorimetry, IBR approved for Sec.  60.335(b)(10)(ii).
    (68) ASTM D4629-02, Standard Test Method for Trace Nitrogen in 
Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and 
Chemiluminescence Detection, IBR approved for Sec.  60.335(b)(9)(i).
    (69) ASTM D5453-00, Standard Test Method for Determination of Total 
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet 
Fluorescence, IBR approved for Sec.  60.335(b)(10)(i).
    (70) ASTM D5504-01, Standard Test Method for Determination of 
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography 
and

[[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]

0
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 NOX 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.

0
4. Section 60.332 is amended by:
0
a. Revising the terms to the equations in paragraphs (a)(1) through 
(2);
0
b. Redesignating paragraph (a)(3) as (a)(4);
0
c. Revising newly designated paragraph (a)(4); and
0
c. Adding a new paragraph (a)(3).
    The revisions and additions read as follows:


Sec.  60.332  Standard for nitrogen oxides.

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


Where:

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

    (2) * * *

Where:

STD = allowable ISO corrected (if required as given in Sec.  
60.335(b)(1)) NOX emission concentration (percent by volume 
at 15 percent oxygen and on a dry basis),
Y = manufacturer's rated heat rate at manufacturer's rated 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 = NOX 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 NOX 
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 NOX 
emission allowance for fuel-bound nitrogen, F shall be defined 
according to the nitrogen content of the fuel during the most recent 
performance test required under Sec.  60.8 as follows:

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

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


Sec.  60.333  Standard for sulfur dioxide.

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

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


Sec.  60.334  Monitoring of operations.

    (a) Except as provided in paragraph (b) of this section, the owner 
or operator of any stationary gas turbine subject to the provisions of 
this subpart and using water or steam injection to control 
NOX emissions shall install, 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 NOX emissions may, as an alternative to operating 
the continuous monitoring system described in paragraph (a) of this 
section, install, certify, maintain, operate, and quality-assure a 
continuous emission monitoring system (CEMS) consisting of 
NOX and O2 monitors. As an alternative, a 
CO2 monitor may be used to adjust the measured 
NOX 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 NOX 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 NOX) and a percent O2 
basis for oxygen; or
    (ii) On a ppm at 15 percent O2 basis; or
    (iii) On a ppm basis (for NOX) and a percent 
CO2 basis (for a CO2 monitor that uses the 
procedures in Method 20 to correct the NOX 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 
NOX and diluent, the data acquisition and handling system 
must calculate and record the hourly NOX emissions in the 
units of the applicable NOX emission standard under Sec.  
60.332(a), i.e., percent NOX by volume, dry basis, corrected 
to 15 percent O2 and International Organization for 
Standardization (ISO) standard conditions (if required as given in 
Sec.  60.335(b)(1)). 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 (Ta), and minimum combustor 
inlet absolute pressure (Po) into the ISO correction 
equation.
    (iii) If the owner or operator has installed a NOX 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 NOX 
emissions, the owner or operator may, for purposes of determining 
excess emissions, use a CEMS that meets the requirements of paragraph 
(b) of this section. Also, if the owner or operator has previously 
submitted and received EPA or local permitting authority approval of a 
petition for an alternative procedure of continuously monitoring 
compliance with the applicable NOX emission limit under 
Sec.  60.332, that approved procedure may continue to be used, even if 
it deviates from paragraph (a) of this section.

[[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 
NOX emissions may elect to use either the requirements in 
paragraph (a) of this section for continuous water or steam to fuel 
ratio monitoring or may use a NOX CEMS installed, certified, 
operated, maintained, and quality-assured as described in paragraph (b) 
of this section.
    (e) The owner or operator of any new turbine that commences 
construction after July 8, 2004, and which does not use water or steam 
injection to control NOX emissions may elect to use a 
NOX CEMS installed, certified, operated, maintained, and 
quality-assured as described in paragraph (b) of this section. An 
acceptable alternative to installing a CEMS is described in paragraph 
(f) of this section.
    (f) The owner or operator of a new turbine who elects not to 
install a CEMS under paragraph (e) of this section, may instead perform 
continuous parameter monitoring as follows:
    (1) For a diffusion flame turbine without add-on selective 
catalytic reduction controls (SCR), the owner or operator shall define 
at least four parameters indicative of the unit's NOX 
formation characteristics and shall monitor these parameters 
continuously.
    (2) For any lean premix stationary combustion turbine, the owner or 
operator shall continuously monitor the appropriate parameters to 
determine whether the unit is operating in the lean premixed (low-
NOX) combustion mode.
    (3) For any turbine that uses SCR to reduce NOX 
emissions, the owner or operator shall continuously monitor appropriate 
parameters to verify the proper operation of the emission controls.
    (4) For affected units that are also regulated under part 75 of 
this chapter, if the owner or operator elects to monitor NOX 
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 NOX emission controls. The 
plan shall include the parameter(s) monitored and the acceptable 
range(s) of the parameter(s) as well as the basis for designating the 
parameter(s) and acceptable range(s). 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 NOX 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 NOX and diluent CEMS:
    (A) An hour of excess emissions shall be any unit operating hour in 
which the 4-hour rolling average NOX concentration exceeds 
the applicable emission limit in Sec.  60.332(a)(1) or (2). For the 
purposes of this subpart, a ``4-hour rolling average NOX 
concentration'' is the arithmetic average of the average NOX 
concentration measured by the CEMS for a given hour (corrected to 15 
percent O2 and, if required under Sec.  60.335(b)(1), to ISO 
standard conditions) and the three unit operating hour average 
NOX 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 NOX 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 NOX 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.

0
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 NOX 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 NOX 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 NOX 
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 
NOX concentration during the stratification test; or
    (B) If each of the individual traverse point NOX 
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 (NOXo) 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:

NOX=(NOXo)(Pr/
Po)0.5 e19 (Ho-0.00633) (288[deg]K/
Ta)1.53

Where:
NOX = emission concentration of NOX at 15 percent 
O2 and ISO standard ambient conditions, ppm by volume, dry 
basis,
NOXo = mean observed NOX concentration, ppm by 
volume, dry basis, at 15 percent O2,
Pr = reference combustor inlet absolute pressure at 101.3 
kilopascals ambient pressure, mm Hg,
Po = observed combustor inlet absolute pressure at test, mm 
Hg,
Ho = observed humidity of ambient air, g H2O/g 
air,
e = transcendental constant, 2.718, and
Ta = ambient temperature, [deg]K.

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