Federal Register: July 8, 2004 (Volume 69, Number 130)

DOCID: FR Doc 04-14825

ENVIRONMENTAL PROTECTION AGENCY

Veterans Affairs Department

CFR Citation: 40 CFR Part 60

RIN ID: RIN 2060-AK35

OAR ID: [OAR-2002-0053, FRL-7780-6]

NOTICE: Part III

DOCUMENT ACTION: Final rule; amendments.

SUBJECT CATEGORY:

Standards of Performance for Stationary Gas Turbines

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.

DOCUMENT 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.

SUMMARY:

Environmental Protection Agency,

SUPPLEMENTAL 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:
Category NAICS SIC Examples of regulated entities 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.

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. OAR20020053. 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) 5661744. The telephone number for the Air Docket is (202) 5661742. 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) 5415384.

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
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EPA's responses to each public comment is available in Docket ID No. OAR20020053.

Outline. The information presented in this preamble is organized as follows:
I. Background
II. Discussion of Revisions

A. Continuous Monitoring Options

B. Optional FuelBound 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 casebycase 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 15minute 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 casebycase 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 4hour 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 24hour 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 4hour 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 FuelBound Nitrogen Allowance

The NOX emission standard in 40 CFR 60.332 includes a NOX emission allowance for fuelbound nitrogen. The use of this allowance for fuelbound 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 fuelbound nitrogen. Therefore, these facilities are not likely to use the fuelbound 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 fuelbound nitrogen. For sources that do not seek to use the fuelbound 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 720hour 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) D259794 (1999), ASTM D636699, ASTM D462902, or ASTM D576202 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 fuelbound 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 fuelbound nitrogen present to claim a credit. Any source owner proposing credit for fuelbound 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 D303181 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 D408482 or 94, D550401, D622898, or the Gas Processors Association Method 237786. 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 D652200 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
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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 21minute 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 addon 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 addon 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
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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 casebycase 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 midrange 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 midrange turbines subject to the NSPS because the vast majority of these turbines have neither CEMS nor an EPAapproved 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 midrange 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 midrange 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 F14a or F14b 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 qualityassured 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 casebycase 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 NOXdiluent 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 biasadjusted 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 biasadjusted.

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 preapproved options for sources that do not want to seek casebycase 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 midrange 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 gasfired 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 preapproved options for sources that do not want to seek casebycase 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 4hour 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 4hour 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 4hour 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 online 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 4hour
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 welloperated 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 90to100 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 D652200 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 D652200 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 ru

FOR FURTHER INFORMATION CONTACT

Mr. Jaime Pagan, Combustion Group, Emission Standards Division (C43901), U.S. EPA, Research Triangle Park, North Carolina 27711; telephone number (919) 5415340; facsimile number (919) 5415450; electronic mail address pagan.jaime@epa.gov.

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