Revision of Standards of Performance for Nitrogen Oxide Emissions From New Fossil-Fuel Fired Steam Generating Units; Revisions to Reporting Requirements for Standards of Performance for New Fossil-Fuel Fired Steam Generating Units

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[FRL-6159-2]

RIN 2060-AE56

Revision of Standards of Performance for Nitrogen Oxide Emissions

From New Fossil-Fuel Fired Steam Generating Units; Revisions to

Reporting Requirements for Standards of Performance for New Fossil-Fuel

Fired Steam Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: Pursuant to section 407(c) of the Clean Air Act, the EPA has

reviewed the emission standards for nitrogen oxides (NOX)

contained in the standards of performance for new electric utility

steam generating units and industrial-commercial-institutional steam

generating units. The EPA proposed revisions to 40 CFR part 60,

subparts Da and Db based on this review on July 9, 1997. The EPA

received 70 public comments on the proposed rule changes. These

comments were reviewed, and this document reflects the EPA's responses

to the issues raised by the commenters. This action promulgates the

revised standards of performance.

The final revisions change the existing standards for

NOX emissions by reducing the numerical NOX

emission limits for both utility and industrial steam generating units

to reflect the performance of best demonstrated technology. The final

revisions also change the format of the revised NOX emission

limit for new electric utility steam generating units to an output-

based format to promote energy efficiency and pollution prevention.

However, in a change from the proposed language, the EPA is revising

the standard for existing utility boilers that become subject to

subpart Da through modification or reconstruction to be in an

equivalent input-based format.

As a separate activity, the EPA also reviewed the quarterly sulfur

dioxide (SO2), NOX, and opacity emission

reporting requirements of the utility and industrial steam generating

unit regulations contained in subparts Da and Db. The final rules will

allow owners or operators of affected facilities to meet the quarterly

reporting requirements of both regulations by means of electronic

reporting, in lieu of submitting written compliance reports.

DATES: Effective Date: The rule revisions are effective November 16,

1998.

Judicial Review: Under CAA section 307(b)(1), judicial review of

this nationally applicable final action is available only by the filing

of a petition for review in the U.S. Court of Appeals for the District

of Columbia Circuit within 60 days of publication of this rule. Under

CAA section 307(b)(2), the regulations that are the subject of this

action may not be challenged later in civil or criminal proceedings

brought by EPA in reliance on them.

ADDRESSES: Docket: All information considered by the EPA in developing

this rulemaking, including public comments on the proposed rules and

other information developed by the EPA in addressing those comments

since proposal, is located in Public Docket No. A-92-71 at the

following address: U.S. Environmental Protection Agency, Air and

Radiation Docket and Information Center (6102), 401 M Street, SW.,

Washington, DC 20460. The docket is located at the above address in

Room M-1500, Waterside Mall (ground floor), and may be inspected from

8:30 a.m. to 4 p.m., Monday through Friday. Materials related to this

rulemaking are available upon request from the Air and Radiation Docket

and Information Center by calling (202) 260-7548 or 7549. The FAX

number for the Center is (202) 260-4400. A reasonable fee may be

charged for copying docket materials.

Technical Support Documents. The technical support documents that

summarize information gathered during EPA's review of the subparts Da

and Db NOX standards and the public comments and EPA's

responses may be obtained from the docket; from the EPA library (MD-

35), Research Triangle Park, North Carolina 27711, telephone number

(919) 541-2777, FAX number (919) 541-0804; or from the National

Technical Information Services, 5285 Port Royal Road, Springfield,

Virginia 22161, telephone number (703) 487-4650. Please refer to ``New

Source Performance Standards, Subpart Da--Technical Support for

Proposed Revisions to NOX Standard'', EPA-453/R-94-012,

``New Source Performance Standards, Subpart Db--Technical Support for

Proposed Revisions to NOX Standard'', EPA-453/R-95-012, or

``New Source Performance Standards, Subparts Da and Db--Summary of

Public Comments and Responses'', EPA-453/R-98-005.

FOR FURTHER INFORMATION CONTACT: For information concerning specific

aspects of this rulemaking, contact Mr. James Eddinger, Combustion

Group, Emission Standards Division (MD-13), U.S. Environmental

Protection Agency, Research Triangle Park, North Carolina 27711,

telephone number (919) 541-5426, electronic mail

``[email protected]''.

SUPPLEMENTARY INFORMATION:

Regulated Entities

Regulated categories and entities include:

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Examples of regulated

Category entities

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Industry.................................. Electric utility steam

generating units,

Industrial steam generating

units, Commercial steam

generating units, and

Institutional steam

generating units.

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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. This table lists the types of entities that the EPA is now

aware of that could potentially be regulated by this action. Other

types of entities not listed in the table could also be regulated. To

determine whether your facility is regulated by this action, you should

carefully examine the applicability criteria in Secs. 60.40a and 60.40b

of the rules. If you have questions regarding the applicability of this

action to a particular entity, consult the person listed in the

preceding FOR FURTHER INFORMATION CONTACT section.

Electronic Access and Filing Addresses

This document, the regulatory texts, and other background

information are available in Docket No. A-92-71 or by request from the

EPA's Air and Radiation Docket and Information Center (see ADDRESSES)

or may be accessed through the EPA web site at: http://www.epa.gov/ttn/

oarpg.

Outline

The following outline is provided to aid in locating information in

this document.

I. Background

A. Statutory and Regulatory Authority

B. Benefits of the NSPS Revisions

C. Public Participation

II. Summary of Final Rules

III. Significant Comments and Changes to the Proposed Revisions

A. Performance of NOX Control Technology

B. Regulatory Approach

C. Modification and Reconstruction

D. Applicability and Exemptions

E. Monitoring

IV. Administrative Requirements

A. Docket

B. Office of Management and Budget (OMB) Review

C. Unfunded Mandates Reform Act

D. Executive Order 12875

E. Executive Order 13084

[[Page 49443]]

F. Regulatory Flexibility Act

G. Executive Order 13045

H. National Technology Transfer and Advancement Act

I. Congressional Review Act

J. Clean Air Act Procedural Requirements

I. Background

A. Statutory and Regulatory Authority

Title IV of the Clean Air Act (the Act), as amended in 1990,

authorizes the EPA to establish an acid rain program to reduce the

adverse effects of acidic deposition on natural resources, ecosystems,

materials, visibility, and public health. The principal sources of the

acidic compounds are emissions of SO2 and NOX

from the combustion of fossil fuels. Section 407(c) of the Act requires

the EPA to revise standards of performance previously promulgated under

section 111 for NOX emissions from fossil-fuel fired steam

generating units, including both electric utility and nonutility units.

These revised standards of performance are to reflect improvements in

methods for the reduction of NOX emissions.

The current standards for NOX emissions from fossil-fuel

fired steam generating units, which were promulgated under section 111

of the Act, are contained in the new source performance standards

(NSPS) for electric utility steam generating units (40 CFR 60.40a,

subpart Da) and for industrial-commercial-institutional steam

generating units (40 CFR 60.40b, subpart Db).

B. Benefits of the NSPS Revisions

The revisions being promulgated reflect the Administrator's

determination that the best system of NOX emission reduction

(taking into consideration the cost of achieving such emission

reduction, any nonair quality health and environmental impact and

energy requirements) for these sources is now reflective of flue gas

treatment technologies, particularly selective catalytic reduction

(SCR). The estimated decrease in baseline nationwide NOX

emissions from new, reconstructed, or modified affected sources

resulting from these rule revisions remain unchanged since proposal and

are approximately 23,000 Mg/year (25,800 tons/year) from utility steam

generating units and 18,000 Mg/year (20,000 tons/year) from industrial

steam generating units in the 5th year after proposal. This represents

an approximate 42 percent reduction in the growth of NOX

emissions from new utility and industrial steam generating units

subject to these revised standards. This reduction in NOX

emissions benefits public health. Nitrogen oxides can cause lung tissue

damage, can increase respiratory illness, and are a primary contributor

to acid rain and ground level ozone formation. The Agency's estimate of

the other environmental, energy, cost, and economic impacts also are

unchanged since proposal. (See 62 FR 36957 for more information on

these estimates.)

In addition to direct environmental benefits, the EPA believes that

the output-based format of the final rule will contribute to important

national goals such as pollution prevention. One of the opportunities

for pollution prevention lies in simply using energy efficient

technologies to minimize the generation of emissions. These revisions

promote energy efficiency at utility plants by changing the manner in

which they regulate flue gas NOX emissions. The fuel neutral

format of the final rules also contributes to pollution prevention

opportunities by encouraging the use of clean fuels without limiting

the control options available for compliance.

A third major benefit of these revisions is that the final rules

reduce the reporting burden for units subject both to NSPS subpart Da

or Db and to other program(s) such as the Acid Rain or NOX

Budget Program. Therefore, the EPA will allow the SO2,

NOX, and opacity reports currently required under subpart Da

or Db to be submitted electronically in lieu of written reports. To

implement this electronic reporting option, special electronic data

report (EDR) record types would have to be created to accommodate the

compliance information required by subparts Da and Db, and sources

would be required to obtain an agreement from their EPA Regional office

and State authority to use the EDR format. The use of this report form

is optional.

C. Public Participation

Prior to proposal, the EPA met with industry representatives

several times to discuss the data and information used to develop the

proposed revisions. In addition, equipment vendors, State regulatory

authorities, and environmental groups had opportunity to comment on the

background information that was prepared for the proposed revisions. In

addition, representatives from other EPA offices and programs have been

included in the regulatory development process as members of the Work

Group.

The proposed revisions were published in the Federal Register on

July 9, 1997 (62 FR 36948). The preamble to the proposed revisions

discussed the availability of technical support documents, which

described in detail the information gathered during the standards

review. Public comments were solicited at proposal.

To provide interested persons the opportunity for oral presentation

of data, views, or arguments concerning the proposed standards, a

public hearing was held on August 8, 1997, at Research Triangle Park,

North Carolina. However, the four scheduled speakers decided to submit

written comments in place of attending the hearing, so no information

was presented at the hearing.

The original public comment period was from July 9, 1997 to

September 8, 1997. The EPA extended the public comment period to

October 8, 1997 based on requests from commenters. During the public

comment period, the EPA received 70 public comment letters on the

proposed rule changes. In the post-proposal period, the EPA met with

several industry representatives to learn more of their concerns

regarding the proposed revisions and to gather additional information

in order to respond to the public comments. Records of these contacts

are found in the final rulemaking docket. All of the comments have been

carefully considered, and, where determined to be appropriate by the

Administrator, changes have been made in the proposed standards based

on the comments received.

II. Summary of Final Rules

The final standards revise the NOX emission limits for

steam generating units in subpart Da (Electric Utility Steam Generating

Units) and subpart Db (Industrial-Commercial-Institutional Steam

Generating Units). Only those electric utility and industrial steam

generating units for which construction, modification, or

reconstruction is commenced after July 9, 1997 would be affected by

these revisions.

The NOX emission limit in the final rule for newly

constructed subpart Da units is 200 nanograms per joule (ng/

JO) (1.6 lb/megawatt-hour (MWh)) gross energy output

regardless of fuel type. For existing sources that become subject to

subpart Da through modification or reconstruction, the NOX

emission limit is 65 ng/JI [0.15 pounds per million BTU (lb/

MMBtu)] heat input. For subpart Db units, the NOX emission

limit being promulgated is 87 ng/JI (0.20 lb/MMBtu) heat

input from the combustion of natural gas, oil, coal, or a mixture

containing any of these fossil fuels; however, for low heat release

rate units firing natural gas or distillate oil, the current

NOX emission limit of 43 ng/JI (0.10 lb/MMBtu)

heat input is unchanged.

[[Page 49444]]

Compliance with the proposed NOX emission limit is

determined on a 30-day rolling average basis, which is the same

requirement that was in effect prior to the revisions. The EPA has

added compliance and monitoring provisions that explain how sources are

to demonstrate compliance with the output-based standards. These

provisions will not increase the overall burden of sources to

demonstrate compliance with the standards beyond what is already

required of sources in the absence of these changes.

The revisions to the quarterly SO2, NOX, and

opacity reporting requirements of subparts Da and Db allow electronic

quarterly reports to be submitted in lieu of the written reports

currently required under Secs. 60.49a and 60.49b. The electronic

reporting option would be available to any affected facility under

subpart Da or Db, including units presently regulated under those

subparts. Each electronic quarterly report would be submitted no later

than 30 days after the end of the calendar quarter.

The format of the electronic report would be coordinated with the

permitting authority. Each electronic report would be accompanied by a

certification statement from the owner or operator indicating whether

compliance with the applicable emission standards and minimum data

requirements was achieved during the reporting period. Owners or

operators would also be required to coordinate with their EPA Regional

Office and State authority to ensure that the permitting authority

agrees to receive reports in the EDR format.

The EPA has determined that acid rain continuous emissions

monitoring systems (CEMS) can be used as NSPS CEMS. However, all CEMS

must generate reports according to the requirements of the applicable

subpart. For example, the acid rain CEMS missing data procedures are

not acceptable under subpart Da. Under subpart Da, emission limits

during hours of invalid data must be met according to the requirements

of Sec. 60.47a(f), which would supersede the acid rain CEMS procedures.

III. Significant Comments and Changes to the Proposed Revisions

Following is a discussion of the significant comments received on

the proposed revisions and the resulting changes, if any, in the final

rules. The document, ``New Source Performance Standards, Subparts Da

and Db--Summary of Public Comments and Responses'' (EPA 453-R-98-005)

contains a more detailed summary of all of the comments and responses.

It also contains the explanation for minor editorial corrections made

in the final revisions.

A. Performance of NOX Control Technology

1. Selective Catalytic Reduction (SCR)

Several commenters raised concerns that the EPA's determination

that SCR represents the best demonstrated technology (BDT) is not

adequate. For example, commenters stated that the EPA should not

consider SCR as BDT for coal-fired industrial boilers, because it has

only been installed on 7 coal-fired units in the U.S., all of which are

electric utility units. In addition, none of the 200 European and

Japanese units with SCR cited by the EPA are industrial units.

Commenters also urged that the EPA consider the potential problems

associated with SCR, including costs, catalyst poisoning, and oil ash

coating the catalyst, when finalizing the NSPS. Another technical issue

raised was that excess SO3 can lead to increased downstream

corrosion and negative impacts on the heat rate of the unit.

Commenters also said that the relevant technologies are immature,

and that EPA has insufficient data to develop a standard that fully

accounts for the variabilities inherent in operating these new

technologies. Other commenters added that the reported cases of

successful SCR applications are extremely limited, with success being

measured on the basis of short-term performance and without cost

considerations.

Commenters raised similar concerns for coal-fired utility boilers.

That is, they said the technology is still in the developmental phase,

and there are insufficient cases where the performance of the

technology has been adequately demonstrated.

The first issue raised by several of the commenters is that EPA's

determination that SCR represents BDT for a range of boiler types and

operating conditions is not adequate. The EPA disagrees and believes

the data base that supports the BDT decision is adequate for two

reasons. First, the proposal data base resulted from an extensive

review of information on the available domestic and international SCR

units in use in the industry at the present time. However, in response

to the comments, the EPA has obtained data from three more utility

boilers that utilize SCR and represent a range of operating conditions

and coal types. The first utility boiler (U.S. Generating Company's

Logan plant) is a 225-megawatt pulverized-coal cogeneration facility,

and is operated under cycling conditions. This facility submitted 3

months of NOX emission data to the EPA. The analysis of

these data indicate that the facility is capable of achieving the

input-based NOX standard of 65 ng/JI (0.15 lb/

MMBtu) and the revised output-based standard of 200 ng/JO

(1.6 lb/MWh) gross energy output on a 30-day rolling average. (See

section III.B.3 for a discussion of the development of the revised

output-based standard.) The second plant is the Birchwood Power

Facility, which is a 240-megawatt cogeneration facility with cycling

load that began operation in 1996. Actual, short-term test results show

that the facility achieves NOX emissions of 97 ng/

JO (0.77 lb/MWh), easily attaining the NSPS output-based

standard. The third facility, Stanton Energy, is a 464-megawatt utility

boiler firing bituminous coal. This facility is currently meeting its

permitted emission limit of 74 ng/JI (0.17 lb/MMBtu). If

this facility were to improve the performance of its SCR to 65 ng/

JI (0.15 lb/MMBtu), this facility would be capable of

meeting the 200 ng/JO (1.6 lb/MWh) output-based limit.

Second, the data base is adequate to evaluate the factors that can

potentially affect SCR performance in a wide range of operating

conditions. Fundamentally, like all post-combustion control devices,

SCR is designed to respond to the characteristics of the stack gas. The

primary difference between utility and non-utility boiler types may be

that, on average, non-utility boilers may be more likely to operate

with fluctuating loads. This difference in operating pattern may appear

to have an impact on the characteristics of the stack gas. However, the

NSPS is based on a 30-day averaging period to accommodate normal

fluctuations in performance. Further, as discussed above, new analyses

of two facilities that operate under cycling conditions have shown that

SCR can meet the revised standard over a 30-day averaging period. The

Birchwood facility reports daily cycle variations from 32 percent to

100 percent of load. The Logan facility's daily cycles ranged from 28

percent to 84 percent in the 3-month period for which data were

supplied.

Another load-related technical issue raised is the difficulty in

maintaining the temperatures necessary to minimize NOX and

HAP generation. In general, while designing an SCR system for a boiler,

the boiler duty is taken into consideration. Specifically, the expected

temperature range at the exit of the economizer is factored in the

selection of an SCR catalyst formulation.

[[Page 49445]]

There are other steps that operators can take to ensure the desired

SCR performance under variable or low load conditions. For example, if

low load contributes to insufficient gas velocity to keep the flyash in

suspension, the operator can add an ash hopper to divert the ash from

the reactor and catalyst face. Alternatively, good ductwork system

design can avoid these problems. Also, low boiler exit temperatures can

be avoided by adding a economizer by-pass to keep the gas temperature

higher at low loads. Finally, good flue gas mixing can overcome

differences in gas flows and boiler firing conditions. Taking into

consideration all of the above, in general, the EPA does not believe

that SCR use is constrained by boiler duty.

Several commenters raised catalyst poisoning as an illustration

that SCR is not suitable for all units. As a result of developments in

catalyst technology, formulations are currently available that minimize

the impact of poisoning. Nevertheless, the EPA believes this issue is

really related to the cost of operating the SCR; appropriate catalyst

management plans now make it possible to maximize catalyst life under

plant operating conditions.

Another issue raised by commenters is that the SCR technology is

immature and insufficiently demonstrated. The EPA disagrees with this

comment. One recent study (Khan, S., et al., ``SCR Applications:

Addressing Coal Characteristic Concerns.'' Presented at the EPRI-DOE-

EPA Combined Utility Air Pollutant Control Symposium, August 1997)

identified at least 212 worldwide SCR installations on coal-fired

units, which cover different types of boilers subjected to varying

operating conditions and firing a variety of coals. Some of these

installations were designed for and have achieved high NOX

reduction levels, exceeding 90 percent. Plants in Europe have been

continuously using SCR for over 10 years. Finally, SCR-equipped units

located in the U.S., such as the Logan, Birchwood, and Stanton

facilities, are meeting some of the most stringent NOX

limits in the country.

2. Coal-related Issues

Several commenters expressed their concern that the proposed NSPS

are not adequately demonstrated for all U.S. coals, particularly

medium- and high-sulfur coals. They said that German and Japanese

experience with these coals is undocumented, or, in the case of Japan,

is with SCRs using hot-side electrostatic precipitators (ESPs) in a

low-dust environment, compared to most U.S. boilers, which use cold-

side ESP's in a high-dust environment. The commenters also rejected the

Department of Energy Plant Crist high-sulfur coal demonstration project

because of its limited scope.

The EPA disagrees that the use of SCR for high-sulfur coal

applications is unsupported. In addition to one coal-fired plant in

Japan and another in Austria firing coals with sulfur contents of 2.5

percent or higher, there are two coal-fired SCR installations in the

U.S. that are firing coals with sulfur contents close to 2 percent. The

Northampton generating facility, which is equipped with SNCR,

successfully burns waste coal, and meets some of the most stringent

NOX limits in the U.S. (0.10 lb/MMBtu). In the Plant Crist

demonstration project, the catalysts from various suppliers performed

successfully. Criteria for successful performance at this demonstration

included ammonia slip less than 5 ppm and SO2 oxidation less

than 0.75 percent.

In view of the experience both in the U.S. and abroad, the

commenters' concerns over the use of SCR for high-sulfur coal

applications is unsupported. In general for these installations, design

features such as low ammonia slip, a catalyst that minimizes

SO3 conversion, and an economizer bypass to maintain proper

flue gas temperatures at low loads are provided.

3. Selective Noncatalytic Reduction (SNCR)

Other commenters argued that SNCR was not adequately demonstrated

on fluidized bed combustion boilers (FBCs) and/or large boilers. One

commenter noted that the EPA's data showed that three of the five

circulating FCBs that use SNCR stated that SNCR did not work properly

when the units were operated at anything less than maximum capacity.

Another commenter said SNCR ``has not been adequately demonstrated to

work on large boilers (with a rated capacity greater than 390 MMBtu/

hr), whether circulating bed or not.''

Flue gas temperatures exiting the furnace can range from 1,200

deg.C 110 deg.C (2,200 deg.F 200 deg.F) at

full load down to 1,040 deg.C 70 deg.C (1,900 deg.F

125 deg.F) at half load. At similar loads, temperatures

can increase by as much as 30 to 60 deg.C (50 to 110 deg.F) depending

on the extent of ash deposition on heat transfer surfaces. Due to these

variations in the temperatures, it is often necessary to inject the

reagent at different locations or levels in the upper furnace or

convective pass for effective NOX reduction. A recent

publication summarized the successful retrofit of retractable lances on

a 100-megawatt coal-fired utility boiler equipped with SNCR, which

greatly improved low load performance. Finally, the addition of

hydrogen or other hydrocarbon reducing agent can be injected with the

ammonia to lower the effective temperature range. Similarly, additives

can increase the temperature range of urea application. By taking these

sorts of steps, the EPA believes that operators can successfully

operate SNCR, even under low load conditions.

Recent analysis of NOX emissions data from a 110-

megawatt, base-loaded, circulating fluidized-bed boiler equipped with

SNCR (U.S. Generating Company's Northampton plant) indicates that the

facility is quite capable of meeting the proposed standard. This

facility achieves average input-based emissions of 38 ng/JI

(0.089 lb/MMBtu) and output-based emissions of less than 100 ng/

JO (0.8 lb/MWh), well below the output-based standard of 200

ng/JO (1.6 lb/MWh) gross energy output.

Regarding SNCR on large boilers, the Acid Rain Phase II

NOX Response to Comments Document (p. 212) notes that SNCR

has been demonstrated on coal-fired units as large as 1,230 MMBtu/hr

(Germany) and on oil-fired units as large as 2,900 MMBtu/hr (Niagara

Mohawk's Oswego Station). The SNCR application on Oswego shows that

injectors can effectively penetrate the combustion gas flow in large

boilers. Since the effectiveness of injecting SNCR reagent into large

boiler casings has been proven, and SNCR has been applied to a variety

of boilers, the EPA does not see boiler size as a restriction for

applying SNCR to NSPS sources.

B. Regulatory Approach

1. Fuel Neutral Approach

Several commenters supported a cap on NOX emissions at

the same level for nearly all fuel types, because it allows fuel

switching as a control technology and is an ``important and positive

step toward cleaner air . . . across the nation.'' Commenters stated

that currently, natural gas-fired units are subject to the most

stringent standard while coal and residual oil are allowed to emit much

larger quantities of NOX. The proposed rule will remove any

disincentive toward natural gas that has been created by this

situation. One commenter wrote that a fuel neutral standard would not

penalize any particular industry, but would encourage competition for

new efficient boilers and cogeneration units, and would be consistent

with the EPA's emphasis on pollution prevention.

[[Page 49446]]

Other commenters opposed the same NOX emission limit for

all fuel types arguing that it sets a lower than lowest achievable

emission rate (LAER) and best available control technology (BACT) level

for coal-fired boilers, while significantly relaxing standards for

natural gas units by a factor of two to four times. Another commenter

stated that a number of gas- and oil-fired units in the U.S. currently

achieve approximately one-tenth of the proposed limit with the

application of SCR.

Commenters stated that the ``proposal violates the Act by providing

an overwhelming incentive for new and modified electric generating

units to burn natural gas to the exclusion of coal.'' Other commenters

opposed the fuel neutral approach because of fuel availability and cost

factors. One commenter stated that natural gas is not uniformly

distributed and evenly available to all industrial users. The commenter

asserted that the proposed emission limit ``favors industrial

development in regions that have an ample supply of natural gas and

penalizes regions that have no practical option for steam production at

industrial facilities other than coal.''

One commenter said the fuel neutral emission rate may inadvertently

be a dis-benefit to the introduction of low NOX technology.

The commenter postulated that ``the result then might be continued

operation of older more polluting sources than might otherwise occur.''

The EPA disagrees with the commenters who contend that the fuel

neutral format creates an overwhelming or disproportionate incentive to

use fuels other than coal. The EPA's approach is designed to allow the

continued use of coal as a fuel in those cases where it is desirable.

The standard would, however, also not discourage conversion to natural

gas where it makes sense in the individual application.

The EPA believes the fuel neutral approach will expand the control

options available by allowing the use of clean fuels as a method for

reducing NOX emissions. Since projected new utility steam

generating units are predominantly coal-fired, the use of clean fuels

(i.e., natural gas) as a method of reducing NOX emissions

from these coal-fired steam generating units may give the regulated

community a more cost-effective option than the application of SCR for

meeting the NOX limit. Similarly, for industrial units, the

use of clean fuels as a method of reducing emissions may be a cost-

effective approach for coal-fired and residual oil-fired industrial

steam generating units.

The fuel neutral approach also fits well with section 101(a)(3) of

the Act's emphasis on pollution prevention, which is one of the EPA's

highest priorities. Because natural gas is essentially free of sulfur

and nitrogen and without inorganic matter typically present in coal and

oil, SO2, NOX, inorganic particulate, and air

toxic compound emissions can be dramatically reduced, depending on the

degree of natural gas use. With these environmental advantages, gas-

based control techniques should be viewed as a sound alternative to

flue gas treatment technologies for coal or oil burning.

Finally, the proposed amendments do not relax the existing NSPS for

natural gas units. In fact, the 65 ng/JI (0.15 lb/MMBtu)

heat input reflects a 50- and 25-percent reduction in NOX

emissions over the current subpart Da limits for oil-fired and gas-

fired units, respectively. Revised subpart Db would not require any

additional controls for new gas-fired and distillate oil-fired units

over the current NSPS because of the costs associated with additional

controls. However, subpart Db does not relax the existing standards for

these units either.

2. Output-Based Format to Subpart Da

Several commenters supported the output-based format of the

proposed subpart Da standard, because they felt it would reward energy-

efficient generators. However, other commenters opposed the format for

the following reasons:

(1) The incentives to be efficient have recently increased due to

the newly competitive nature of the industry, and will continue to

increase without output-based standards.

(2) The format would add significant burdens to an already

complicated monitoring system for utilities.

(3) There are inconsistencies between the proposed NSPS output-

based format and several other input-based regulations that are also

applicable to these sources.

(4) NOX averaging of NSPS units with existing units

would be very complicated.

(5) The output-based format is inappropriate and inaccurate for

cogeneration facilities that produce steam in addition to or in place

of electric generation. Because the customers dictate the temperature

and pressure conditions of the steam that is produced, the generator

has no choice and must produce the desired product. In addition, the

EPA method of equating steam production to electric production was

over-simplified and punitive in that it does not consider all of the

potential steam production conditions, and it would increase the cost

of efficient cogeneration.

(6) An output-based NSPS does not promote energy efficiency because

it ``makes no allowance for the use of low Btu fuels (such as waste

coal) that would otherwise go unused,'' which would increase the costs

of electrical generation and discourage national energy self-

sufficiency. Further, the proposed NSPS is inconsistent with recent

utility deregulation, because ``an important goal of recent utility de-

regulation was to allow market forces to minimize the cost of electric

power to consumers, without eroding environmental protection.''

The EPA continues to believe in the benefits associated with an

output-based standard for new sources that encourages energy

efficiency. As discussed in section III.C, however, the EPA has revised

the final standard for existing sources that become subject to the NSPS

because of modification or reconstruction, to be in the equivalent

input-based format of 65 ng/JI (0.15 lb/MMBtu).

The changes in the output-based format, discussed below in section

III.B.3, will simplify the compliance demonstration for sources by

eliminating the need to convert input values to output values. Given

that the output-based format is a new regulatory approach for these

sources, it is inevitable that some inconsistencies in monitoring

requirements associated with various programs to which individual

sources might be subject would occur. While the EPA is concerned about

these apparent inconsistencies, the EPA also feels that the

requirements of the NSPS stand on their own merits. The NSPS provisions

do not require any new monitoring at sources that is not already

required by some other program (i.e., the Acid Rain program.) However,

in some instances, the Title V permit process and activities such as

permit streamlining may provide relief to sources on a case-by-case

basis. In addition, the EPA will continue to explore additional ways to

provide monitoring relief that do not compromise the ability of EPA to

adequately enforce Federal standards.

As discussed below in section III.B.3, the EPA did examine possible

revisions to the steam credit allowance for cogeneration facilities.

These issues are further addressed in that section.

Finally, the EPA believes that low-cost fuels can be used

effectively at facilities subject to the final standards. As discussed,

the U.S. Generating

[[Page 49447]]

Company's Northampton facility is currently performing better than

would be required under the amended NSPS and uses waste coal as its

sole energy source.

3. Input to Output Conversion Assumptions

The EPA revised the approach used to develop the output-based limit

based on analysis of comments submitted on the input to output

conversion assumptions relied on in developing the proposed standard.

As discussed in detail in this section, the EPA will finalize the

standard for new sources at a level of 200 ng/JO (1.6 lb/

MWh) gross energy output. The revised standard contained in this final

rule is based on actual measured energy output, rather than measured

heat input converted to energy output, as was the case with the

proposed standard. This change addresses concerns related to overall

heat rates, steam credits for cogeneration facilities, and gross versus

net output. The key underlying assumption inherent in the selection of

the level of the final standards at 200 ng/JO (1.6 lb/MWh)

gross output, i.e., the input-based standard of 65 ng/JI

(0.15 lb/MMBtu), is maintained.

38-Percent Baseline Efficiency. There were comments both in support

of and opposed to the selection of an average 38-percent baseline

boiler efficiency. The selection of a baseline efficiency value is

intimately tied to the selection of a corresponding heat rate. Based on

data available since the proposed standards, the Agency has been able

to evaluate heat rate directly.

9,000 Btu/kWh Heat Rate. The majority of commenters opposed the

selection of an assumed 9,000 Btu/kWh heat rate for use in converting

input-derived NOX emissions to an output basis. Several

commenters provided examples of units that operate in the 10,000 to

11,000 Btu/kWh range. The commenters indicated that net heat rates of

10,000 to 10,500 Btu/kWh are typical of state-of-the-art units.

In light of additional data supplied by commenters and collected by

EPA, the EPA has decided to revise the assumed heat rate. First, as

explained later, the output-based standard is now based on gross output

instead of net output, so the following discussion will be in terms of

gross heat rates.

The EPA collected data from four additional utility boilers that

are considered to be new and state-of-the-art from an emissions

standpoint. The first boiler is a base-loaded, fluidized bed combustion

cogeneration unit that fires waste coal and is equipped with SNCR

(Northampton). This unit's average gross heat rate (with 50 percent

credit for export steam) is less than 9,000 Btu/kWh. The second unit is

a pulverized coal-fired, cogeneration unit that operates under cycling

load and is equipped with SCR (Logan). This unit's average gross heat

rate (with 50 percent credit for export steam) is approximately 10,250

Btu/kWh. The third utility boiler (Stanton) has an average heat rate of

10,250 Btu/kWh. The Birchwood cogeneration unit, the fourth facility,

reported that they cycle between heat rates of approximately 10,700

Btu/kWh at 32 percent load and 9,000 Btu/kWh at 100 percent load. The

heat rates reported by the Birchwood cogeneration unit are based on a

100 percent credit for export steam.

The EPA conducted statistical analyses in which the objective was

to assess long-term NOX emission levels, on an output basis,

that can be achieved continuously. Statistically, Logan, Northampton,

and Birchwood all can meet the revised output-based standard of 200 ng/

JO (1.6 lb/MWh) (gross) on a 30-day rolling average.

Cogeneration Steam Credit. Several commenters asserted that using

only 50 percent of the thermal energy from the steam generated at

cogeneration facilities in calculations of output-based emission rates

is inappropriate. The commenters reported that the 50-percent

allocation is from a section of the Public Utility Restructuring Policy

Act (PURPA) in which the 50-percent thermal output is used as part of a

definition of a PURPA-qualifying facility. Basing the NSPS on this

factor is not justified according to the commenters. The commenters

also suggested a variety of ways to calculate the steam credit

including (1) converting the electric output to MMBtu plus the enthalpy

of the full steam or hot water output in MMBtu, or the electric output

in MWhel plus the enthalpy of the full steam or hot water

output in MWhth, (2) measuring pounds of NOX per

million Btu of steam produced at the boiler steam header, or (3)

measuring the electric output plus the full thermal output in

consistent units. Another commenter suggested that since each

application would differ in efficiency, credit should be given for the

heat actually used and calculated on a case-by-case basis.

Other commenters insisted that efficiency should not be used as a

compliance measure. The commenter explained that the efficiency

calculation is an extra, unneeded step. The commenters reported that

all that is needed is a CEMS to directly measure NOX and an

electric or thermal measurement for output in units of MMBtu or MWh.

As discussed, the EPA has revised the form of the final standards

to be based on a direct measure of output, i.e., mass of NOX

per unit of gross energy output. In order to evaluate the data

supporting the level of the standard, the EPA had to conduct data

analysis to address the level of steam credit for cogeneration

facilities. The EPA considered three approaches for addressing the

issue of steam credit for cogeneration facilities: (1) Allow credit for

steam as if it were being converted into electricity; (2) Allow credit

in the form of 50 percent of the thermal value (enthalpy) of the steam;

and (3) Allow credit for greater than 50 percent of the value of the

steam, up to 100 percent.

The EPA decided not to allow credit for steam as if it were being

converted into electricity because the EPA wants to encourage

cogeneration. Allowing credit as if electricity would only provide

credit for up to 38 percent of the value of the steam, which is the

reported maximum of the efficiency of steam to electricity conversion.

The EPA also decided not to allow for greater than 50-percent

credit for the steam. Based on analysis of heat rates for cogeneration

facilities, the EPA has determined that once a facility exceeds 50

percent and approaches 100 percent credit for the steam, there is a

potential for calculating an artificially high output rate,

particularly if much of the steam is exported. As another option, the

EPA considered allowing 100 percent credit for steam, but capping the

amount of steam for which credit could be received to a certain

percentage of total output. This approach was deemed to be too complex

from a monitoring standpoint.

Therefore, the EPA retained the proposed 50-percent credit for

export steam from cogeneration facilities on the basis that it

encourages cogeneration, will not result in artificially high output

rates, and will not require complex monitoring. This outcome is based

on the information available to the Agency at this time. We recognize,

however, that cogeneration increases the efficiency of power generation

and, as discussed above, comments received during the rulemaking

process indicate that there may be alternative ways of calculating the

value of thermal output that warrant further consideration. We are

interested in exploring alternative approaches to cogeneration and

request further comment on this issue. We particularly are interested

in hearing about alternatives that would allow us to determine the

fraction of the energy delivered to the industrial process that

[[Page 49448]]

is actually used and should, therefore, be included in the calculation

of the gross output from cogeneration facilities.

Gross Versus Net Output. While some commenters support the use of a

net output basis to the final format of the standard because it

encourages energy efficiency at the facility, several other commenters

raised concerns regarding how net output would actually be measured in

the industry. One commenter reported that the output-based format would

``require significant and costly changes to the software of monitoring

and reporting systems.'' Other commenters reported that electrical

output cannot be measured directly because it is dependent on the

``electrical usage by hundreds of motors and other auxiliary equipment

located throughout the plants.'' They claimed that net generation

cannot be measured ``by simply installing a wattmeter.''

One commenter recommended basing the standards on gross rather than

net output to account for the power drain associated with many types of

control technologies. Other commenters protested that the proposal did

not include a specific methodology for determining the unit net output.

They said the EPA did not provide for a subsequent comment period on a

``significant component'' of the proposal, and the EPA should withdraw

the proposal until a complete and thorough package can be provided for

full public review and comment.

The EPA has reconsidered its position, and has decided to finalize

the rule based on the use of gross output because of the monitoring

difficulties inherent in the net output methodology. In particular,

measuring net output at facilities with both affected and nonaffected

units could be problematic, because a single meter on the electricity

leaving the facility could not effectively allocate the electricity

leaving the affected boiler. The EPA may revisit this issue should EPA

develop a methodology to determine the net heat output in all

circumstances.

C. Modification and Reconstruction

Commenters expressed opposition to the applicability of the NSPS to

modified units. They said that Congress' intent in developing the NSPS

program was to limit applicability to sources that could be designed to

include state-of-the-art pollution control technology, and that the

emphasis on new sources reflected Congress' recognition of the

difficulty and expense of retrofitting control technology on existing

sources.

One commenter said that the EPA was ``acting unlawfully by failing

to consider the costs that will be incurred by existing sources that

become the subject of the proposed NOX standard.'' The

commenter proffered that existing coal-fired sources are likely to

become subject to this rule eventually, unless they are specifically

excluded. According to this commenter, if this occurs, the existing

sources will be faced with excessive retrofit costs in order to attain

the standard.

One commenter stated that ``the installation of SCR on existing

units * * * would be economically infeasible.'' A possible solution

proposed by a commenter was that the EPA propose a standard that

modified units could meet without SCR, or justify the use of the same

standards as for new units. One commenter reasoned that ``since EPA

states that few modified sources will be affected, adding specific

language clarifying that such units are not subject to the NSPS would

raise few, if any, policy implications.'' Another possible solution

presented was that the EPA specifically exclude modified boilers from

the final NSPS.

One commenter stated that the proposed NOX emission

limit was not demonstrated for non-gas-fired modified sources and that

the new limit should not apply to sources that come under the NSPS

through modification. In situations where liquid or solid fuel is

fired, it is not always possible or reasonable to comply with the

proposed limit. For instance, the commenter has a residual oil-fired

boiler that could not be retrofitted to meet the proposed standard, and

add-on controls would not be feasible because of limited space and

unreasonable cost.

One commenter said EPA is aggressively pursuing businesses that

have made efficiency improvements to force the units to meet NSPS under

the modification provisions in 40 CFR part 60. The commenter stated

that the EPA ``clearly has the discretion and duty to distinguish

between new and existing sources which become subject to this rule.''

The Clean Air Act defines a modification as ``any physical change

in, or change in the method of operation of, a stationary source which

increases the amount of any air pollutant emitted by such source or

which results in the emission of any air pollutant not previously

emitted.'' (Section 111(a)(4)) Section 60.14 of the subpart A General

Provisions provides additional guidance on EPA's interpretation of this

definition, and specifically excludes changes in ownership of an

existing facility from being considered a modification. (40 CFR 60.14)

In addition, a key aspect to the definition of modification is that the

change to the facility must result in an emissions increase.

Section 111(b)(1)(B) of the Act requires the Administrator to

promulgate standards of performance for ``new sources'' in each

category of sources which in the Administrator's judgment causes, or

contributes significantly to, air pollution which may reasonably be

anticipated to endanger public health or welfare. Section 111(a)(2) of

the Act defines ``new source'' to include stationary sources which are

modified after an applicable standard of performance is proposed. The

EPA finds nothing in the comments that would justify ignoring this

clear statutory mandate. In developing standards of performance,

section 111(a)(1) of the Act does, however, allow the Administrator to

take into consideration the cost of achieving the required reduction

and any nonair quality health and environmental impact and energy

requirements. As noted at proposal, the efficiency of most existing

electric utility steam generating plants ranges from 24- to 38-percent

efficient. The EPA selected 38-percent efficiency as the baseline

reflective of NSPS units. The EPA believes that selecting the 38-

percent efficiency level for new electric utility steam generating

units was an appropriate exercise of its discretion based on the

available information. The EPA realizes, however, that existing units

are likely to operate in the lower end of this range, with higher

associated heat rates, which would make it more difficult to meet an

output-based standard. These sources would have to compensate with

higher control device performance (up to a 40-percent increase in

performance), which would be more costly. To ease this potential

burden, the EPA has decided to allow any existing units that become

subject to the NSPS as a result of undergoing a modification or

reconstruction to meet the equivalent input-based standard of 65 ng/

JI (0.15 lb/MMBtu) on which the output-based standard

applicable to new units is based. This change will eliminate the

concern that higher average heat rates at existing units could

adversely affect a source's ability to meet an output-based standard.

This level of control represents the same overall level of SCR

performance that would be required of new units, but lacks the benefits

attributed to promoting energy efficiency that the output-based format

provides.

[[Page 49449]]

D. Applicability and Exemptions

1. Gas Turbines

Commenters stated that the EPA should not apply the proposed

standard to modified and reconstructed waste heat boilers. The

commenters said these waste heat systems are typically installed in the

ductwork of a gas turbine exhaust and are not amenable to significant

modification for NOX control because of their configuration.

According to the commenters, tubes are tightly packed, space for

reconfiguration is extremely limited, and possible back pressure

impacts on the upstream device are a major concern. Applying the NSPS

would require the combined system to meet the new standard, because the

NOX from the upstream device (i.e., combustion turbine)

cannot be separated from the steam generator NOX for

purposes of add-on control. The commenters said that add-on controls

are not demonstrated for such systems.

The systems described by the commenters would be subject to subpart

GG of this part, standards of performance for stationary gas turbines,

and subparts Da or Db. Because these standards cover separate emission

sources, continued applicability of subparts Da or Db is needed.

However, the EPA's ongoing Industrial Combustion Coordinated Rulemaking

(ICCR) could result in the EPA extending the applicability of subpart

GG to the duct burner, which is currently covered by subparts Da and

Db. The EPA agrees that if this were to occur, the ICCR-driven

revisions to subpart GG would pose a potential conflict with the

subparts Da and Db. Therefore, the EPA will revise subparts Da and Db

to exempt sources that may also become subject to subpart GG, should

such revisions to subpart GG occur.

2. Ten-Percent Exemption

Commenters noted that the proposed revision appears to apply to all

steam generating units, including units that are excluded from the

current standard because they fire 10 percent or less fossil fuel. The

commenters did not believe that the EPA intended that the revised

NOX limit should apply to facilities that combust a limited

amount of fossil fuel. Several commenters suggested clarifying the

following language at the end of Sec. 60.44b(l)(1): ``* * * 86 ng/

JI (0.20 lb/MMBtu) heat input unless the affected facility

has an annual capacity factor for coal, oil, and natural gas of 10

percent (0.10) or less and is subject to a federally enforceable

requirement that limits operation of the facility to an annual capacity

factor of 10 percent (0.10) or less for coal, oil, and natural gas; or

* * *.''

The EPA did not intend to remove the 10-percent exemption from the

revised NSPS. The EPA will add the suggested regulatory language to

clarify that this exemption still applies.

3. Municipal Waste Combustors

Commenters pointed out that, as written, the proposed

NOX revisions would include municipal solid waste combustors

(MWC) that only use a limited amount of fossil fuels for startup

purposes and supplemental fuel during those periods when the heat

content of the waste is low, in order to maintain good combustion

conditions. These units are already subject to subpart Eb of this part,

the revised NSPS for large MWC. The commenters suggested that the

addition of the 10-percent exemption, discussed above, would alleviate

this concern or that exemptions for MWC units subject to the relevant

MWC rules would make sense.

As discussed above, the EPA has included the language regarding the

10-percent exemption to the final rule, which should cover these types

of sources. In addition the EPA will revise the final rule to exempt

units that are subject to subpart Eb to avoid any possible conflicts.

E. Monitoring

Several commenters requested that the EPA clarify and expand the

allowance of the use of part 75 CEMS in place of the subparts Da and Db

required monitoring provisions. In particular, commenters requested

that part 75 elements such as data validation procedures, CEMS

configuration specifications, and methods of compliance determination

should be deemed to satisfy subparts Da and Db monitoring provisions.

In the past, the EPA determined that Acid Rain CEMS can be used as

NSPS Subpart Da CEMS. That determination is available on the Office of

Enforcement and Compliance Assurances's web site. A subpart Db boiler

equipped with an acid rain CEMS can also use this CEMS as a subpart Db

CEMS. In either case, the reports generated by this CEMS must be

generated according to the provisions of subparts Da or Db, as

applicable, and submitted to the authority in charge of the NSPS

program, because the NSPS and acid rain programs have different

requirements and are managed by different authorities.

Regarding data validation procedures, the EPA headquarters already

maintains the acid rain data base and the AIRS data base, which is

suitable for reports from non-acid rain programs. In addition, several

States maintain their own data bases. The EPA believes that the data

validation issue should not lead to any conflicts considering that the

acid rain and the subparts Da and Db report formats must follow their

own requirements. The EPA headquarters has addressed a few span-related

issues upon request and will continue this practice under the part 60

General Provisions. Finally, emission limits during hours of invalid

data must be met using other means than CEMS data according to the

requirements of Sec. 60.47a(f) or Sec. 60.48b(f), as applicable.

The EPA has added language to Sec. 60.47a(c) to clarify that ``If

the owner or operator has installed a nitrogen oxides emission rate

continuous emission monitoring system (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, that CEMS may be used to meet

the requirements of this section, except that the owner or operator

shall also meet the requirements of Sec. 60.49a. Data reported to meet

the requirements of Sec. 60.49a shall not include data substituted

using the missing data procedures in subpart D of part 75 of this

chapter, nor shall the data have been bias adjusted according to the

procedures of part 75 of this chapter. Similar language has also been

added to Sec. 60.48b(b) to clarify the use of part 75 CEMS with subpart

Db affected facilities.

IV. Administrative Requirements

A. Docket

This final rulemaking action is subject to section 307(d) of the

Act. Accordingly, the EPA has established a docket (No. A-91-71), which

consists of an organized and complete file of all information submitted

to, or otherwise considered by, the EPA in the development of this

action. The docket includes all memoranda and studies cited by the EPA

in this preamble. The principal purposes of the docket are: (1) To

allow interested parties a means to identify and locate documents so

that they can effectively participate in the rulemaking process, and

(2) to serve as the record in case of judicial review. The docket is

available for public inspection at EPA's Air Docket, which is listed

under the ADDRESSES section of this document.

[[Page 49450]]

B. Office of Management and Budget (OMB) Review

1. Paperwork Reduction Act

These revisions contain no changes to the information collection

requirements of the current NSPS that would increase the burden to

sources, and the currently approved Office of Management and Budget

(OMB) information collection requests are still in force for the

amended rules. These information collection requests are identified as

number 1053.05, OMB 2060-0023, for 40 CFR 60.40a-49a and number

1088.08, OMB 2060-0072 for 40 CFR 60.40b-49b. 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.

Some changes in the rule, such as allowing the submittal of

electronic reports, are provided as an option to sources, and should

reduce burden to those sources electing to use this report format.

Other rule changes, such as the difference in numerical NOX

emission limits and the output-based format of the standard, do not

result in additional recordkeeping and reporting requirements, beyond

those already required by other programs such as the Acid Rain

requirements in part 75.

2. Executive Order 12866

Under Executive Order 12866 (58 FR 51735, Oct. 4, 1994), the Agency

must determine whether the regulatory action is ``significant'' and,

therefore, subject to OMB review and the requirements of the Executive

Order. The Order defines ``significant'' regulatory action as one that

is likely to lead to a rule that may: (1) have an annual effect on the

economy of $100 million or more, or adversely and materially affect 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; (4) raise novel legal or policy issues arising out of legal

mandates, the President's priorities, or the principles set forth in

the Executive Order.

Pursuant to the terms of Executive Order 12866, the EPA has

determined that this rule is a ``significant regulatory action''

because this action may have an annual effect on the economy of $100

million or more and it raises novel policy issues, such as the output-

based format of the subpart Da emission limit for new sources and the

fuel neutral approach to the emission limits under both subparts. As

such, this action was submitted to OMB for review. Changes made in

response to OMB suggestions or recommendations will be documented in

the public record.

C. Unfunded Mandates Reform Act

Under section 202 of the Unfunded Mandates Reform Act of 1995

(``UMRA''), signed into law on March 22, 1995, the EPA must prepare a

statement to accompany any proposed rule where the estimated costs to

State, local, or tribal governments, or to the private sector, will be

$100 million or more in any one year. Under section 205, the EPA must

select the most cost-effective, least costly, or least burdensome

alternative that achieves the objective of the rule and is consistent

with statutory requirements. Section 203 requires the EPA to establish

a plan for informing and advising any small governments that may be

significantly impacted by the rule.

The unfunded mandates statement under section 202 must include: (1)

A citation of the statutory authority under which the rule is proposed;

(2) an assessment of the costs and benefits of the rule, including the

effect of the mandate on health, safety and the environment, and the

federal resources available to defray the costs; (3) where feasible,

estimates of future compliance costs and disproportionate impacts upon

particular geographic or social segments of the nation or industry; (4)

where relevant, an estimate of the effect on the national economy; and,

(5) a description of the EPA's prior consultation with State, local,

and tribal officials.

Since this final rule is estimated to impose costs to the private

sector in excess of $100 million, the EPA has prepared the following

statement with respect to these impacts.

1. Statutory Authority

The statutory authority for this rulemaking is identified and

described in section I.A of the preamble. As required by section 205 of

the UMRA, and as described more fully in the proposal preamble (62 FR

36948, section III) and section III of this preamble, the EPA has

chosen to promulgate a rule that is the least burdensome alternative

for regulation of these sources that meets the statutory requirements

under the Act.

2. Costs and Benefits

As described in section VI of the proposal preamble, the estimate

of annual social cost for the regulation is $40 million for utility

boilers and $41 million for industrial boilers in the year 2000.

Certain simplifying assumptions, such as no fuel switching in response

to the rule, may have resulted in a significant overestimation of these

costs.

The pollution control costs will not impose direct costs for State,

local, and tribal governments. Indirectly, these entities face

increased costs in the form of higher prices for electricity and the

goods produced in the facilities requiring new industrial boilers that

would be subject to this final rule. There are no federal funds

available to assist State, local, or tribal governments with these

indirect costs.

Because this regulation affects boilers as they are constructed (or

modified), the emission reductions attributable to the regulation

increase year by year until all existing boilers have been replaced. In

the year 2000, the NOX emission reduction relative to the

baseline for utility boilers is estimated to be 26,000 tons per year.

In the year 2000, the NOX emission reduction relative to the

baseline for industrial boilers that represent net additions to

existing capacity is estimated to be 20,000 tons per year. Emissions

reductions from replacement boilers are not quantified because of

difficulties in characterizing emission rates for the boilers being

replaced and the inability of the replacement model to predict

selection of different types of boilers in both the baseline case and

in response to the regulation. A qualitative analysis of industrial

boiler replacement raises the possibility that replacement delay due to

the revision may keep some boilers continuing to emit at a higher level

than they would in the baseline case where they would be replaced by a

lower emitting boiler.

Reducing emissions of NOX has the potential to benefit

society in a number of ways. Emissions of NOX result in a

wide range of damages, ranging from human health effects to impacts on

ecosystems. They not only contribute to ambient levels of potentially

harmful nitrogen compounds, but they also have important precursor

effects. In combination with volatile organic compounds (VOCs), they

contribute to the formation of ground level ozone. Along with emissions

of sulfur oxides, they are also precursors to particulate matter and

acidic deposition.

See Table 2 for a summary of linkages between NOX

emissions and damage categories.

[[Page 49451]]

Table 2.--Linkages Between NOX Emissions and Damage Categories: Strength of the Evidence

----------------------------------------------------------------------------------------------------------------

Direct effects Precursor effects

-------------------------------------------------------------------

Ambient

Ambient NOX Ambient ozone particulate Acid deposition

levels levels matter

----------------------------------------------------------------------------------------------------------------

Human Health:

Acute Morbidity.........................

Chronic Morbidity.......................

Mortality............................... ............... ...............

Ecosystems:

Terrestrial............................. 1 ...............

Aquatic................................. ............... ...............

Commercial Biological Systems 2:

Agriculture............................. ............... ...............

Forestry................................ ............... ...............

Visibility.............................. ............... ...............

Materials............................... ............... ...............

----------------------------------------------------------------------------------------------------------------

= weak evidence.

= limited evidence.

= strong evidence.

\1\ Evidence indicates that NOX can have both positive and negative effects in this category.

\2\ Evidence for this category relates specifically to certain commercial crop or tree types rather than to the

more general terrestrial damages that are covered in the separate ecosystems category.

Benefits are only qualitatively addressed in the regulatory impacts

analysis (RIA) because of difficulties in physically locating the not

yet built boilers and translating their emission reductions into

changes in ambient concentrations of nitrogen compounds, ozone

concentrations, and particulate matter concentrations.

3. Future and Disproportionate Costs

The rule is not expected to have any disproportionate budgetary

effects on any particular region of the nation, any State, local, or

tribal government, or urban or rural or other type of community. Only

very small increases in electricity prices are estimated. See section

VIII C.4 of the proposal preamble for more detail.

4. Effects on National Economy

Significant effects on the national economy from this rule are not

anticipated. See section VIII.C.4 of the proposal preamble for more

detail.

5. Consultation with Government Officials

The UMRA requires that EPA describe the extent of the Agency's

prior consultation with affected State, local, and tribal officials,

summarize the officials' comments or concerns, and summarize the EPA's

response to those comments or concerns. In addition, section 203 of the

Act requires that the EPA develop a plan for informing and advising

small governments that may be significantly or uniquely impacted by a

proposal.

In the development of this rule, the EPA has provided small

governments (State, local, and tribal) the opportunity to comment on

this regulatory program. A fact sheet which summarized the regulatory

program, the control options being considered, preliminary revisions,

and the projected impacts was forwarded to seven trade associations

representing State, local, and tribal governments. A meeting was held

for interested parties to discuss and provide comments on the program.

Written comments also were requested. The main comments received dealt

with the need to consider the impacts of the revisions on small units

and facilities. Commenters also stated that the requirement for an

integrated resource plan is unnecessary and burdensome for small

operators and may constitute an unfunded mandate. In response to this

concern, the EPA removed the requirement for an integrated resource

plan from this rulemaking. In response to the concern regarding the

cost impacts on small industrial steam generating units, the EPA

proposed a higher NOX emission limit for industrial units

than it proposed for utility units. The revised limit for industrial

units effectively results in no additional controls for gas and

distillate oil-fired industrial units over that required to comply with

the current emission limits. As described in sections VIII.D.3 and

D.4.c of the proposal preamble, the impacts on small businesses and

governments have been analyzed and indicate that small governments are

not significantly impacted by this rule and thus no plan is required.

Public comments received from government entities were largely limited

to technical comments on the proposed revisions. However, the City of

Tampa, Florida, did raise a burden-related issue due to concerns

regarding the potential overlap in applicability between subpart Db and

other NSPS provisions affecting municipal waste combustors. As

described in section III.D.3, the EPA has addressed their concerns by

reinstating the 10-percent exemption and by specifically exempting MWC

units from applicability to subpart Db.

D. Executive Order 12875

Under Executive Order 12875, EPA may not issue a regulation that is

not required by statute and that creates a mandate upon a State, local

or tribal government, unless the Federal government provides the funds

necessary to pay the direct compliance costs incurred by those

governments. If the mandate is unfunded, EPA must provide to OMB a

description of the extent of EPA's prior consultation with

representatives of affected State, local and tribal governments, the

nature of their concerns, copies of any written communications from the

governments, and a statement supporting the need to issue the

regulation. In addition, Executive Order 12875 requires EPA to develop

an effective process permitting elected officials and other

representatives of State, local and tribal governments ``to provide

meaningful and timely input in the development of regulatory proposals

containing significant unfunded mandates.''

The EPA has concluded that this rule may create a mandate on State,

local, and/or tribal governments and that the Federal government will

not provide the funds necessary to pay the direct costs incurred by the

State, local and/or tribal governments in complying with the mandate.

These governments will also have the responsibility to carry out the

[[Page 49452]]

rule by incorporating it into permits and enforcing it, as delegated.

They will collect permit fees that pay for the costs of applying the

rule.

In developing this rule, EPA consulted with these governments to

enable them to provide meaningful and timely input in the development

of this rule. As discussed in section IV.C.5 of this preamble, EPA

provided numerous opportunities for these stakeholders to comment on

the proposed amendments and has carefully considered their input.

As described in sections IV.C.2 and IV.C.3, EPA does not expect

this rule to impose direct compliance costs on State, local, and tribal

governments. At most, these entities will face increased indirect costs

in the form of slightly higher prices for electricity and the goods

produced in facilities requiring new industrial boilers that would be

subject to this final rule. Compared to the estimated health and

environmental benefits, described in section IV.C.2 of this preamble,

EPA believes the need to issue this final rule outweighs the potential

costs to these governmental entities.

E. Executive Order 13084

Under Executive Order 13084, EPA may not issue a regulation that is

not required by statute, that significantly or uniquely affects the

communities of Indian tribal governments, and that imposes substantial

direct compliance costs on those communities, unless the Federal

government provides the funds necessary to pay the direct compliance

costs incurred by the tribal governments. If the mandate is unfunded,

EPA must provide to OMB, in a separately identified section of the

preamble to the rule, a description of the extent of EPA's prior

consultation with representatives of affected tribal governments, a

summary of the nature of their concerns, and a statement supporting the

need to issue the regulation. In addition, Executive Order 13084

requires EPA to develop an effective process permitting elected and

other representatives of Indian tribal governments ``to provide

meaningful and timely input in the development of regulatory policies

on matters that significantly or uniquely affect their communities.''

Today's rule does not significantly or uniquely affect the

communities of Indian tribal governments. The EPA received extensive

public comments on the proposed amendments. None of the commenters

raised any issues of direct significance to Indian tribal governments.

Accordingly, the requirements of section 3(b) of Executive Order 13084

do not apply to this rule.

F. Regulatory Flexibility Act

EPA has determined that it is not necessary to prepare a regulatory

flexibility analysis in connection with this final rule. EPA has also

determined that this rule will not have a significant economic impact

on a substantial number of small entities. The Regulatory Flexibility

Act (RFA) requires EPA to give special consideration to the impact of

regulation on small businesses, small organizations, and small

governmental units. The major purpose of the RFA is to keep paperwork

and regulatory requirements from getting out of proportion to the scale

of the entities being regulated, without compromising the objectives

of, in this case, the Clean Air Act. The RFA specifies that the EPA

must prepare an initial regulatory flexibility analysis if a proposed

regulation will have a significant economic impact on a substantial

number of small entities.

Firms in the electric services industry (SIC 4911) are classified

as small by the U.S. Small Business Administration if the firm produces

less than four million megawatts a year. For the time period of the

analysis (1996 to 2000), one projected new utility boiler may be

affected and small. Of the 13 projected new utility boilers, 10 are

known to not be small, and 2 of the remaining 3 are not expected to

incur additional control costs due to the regulation. The size of the

owning entity is unknown for the remaining utility boiler. That boiler

also has the smallest cost in mills/kWh (0.07) of the 11 projected

units to have additional control costs. Therefore, no significant small

business impacts are anticipated for the utility boilers.

Regarding industrial boilers, EPA expects that some small

businesses may face additional pollution control costs. It is difficult

to project the number of industrial steam generating units that will

both incur control costs under the regulation and be owned by a small

entity. Since the rule only affects new sources, and plans for new

industrial boilers are not available (as they are for electric

utilities), linking new projected boilers to size of owning entity is

difficult. The projection of 381 new boilers has 293 of the boilers

incurring no costs because they are projected to be either gas-fired or

distillate-oil-fired units that would require no additional control.

Some of the 88 remaining boilers which are projected to incur costs in

complying with the regulation may be owned by small entities. The size

of the owning entity and the size of the boiler are not related in any

simple way, but smaller entities may be more likely to have a smaller

boiler. The applicability size cut off of 100 million Btu/hour heat

input for industrial boilers would be expected to result in fewer small

entities being affected. Since only 88 industrial boilers are expected

to incur any costs and many of them are likely to be owned by large

entities, the EPA projects that fewer than 88 of these boilers will be

owned by small entities.

The information used for economic impact analysis for the proposed

rule matches boiler size and fuel type to various industries. These

data overestimate the share of boilers that are residual-oil-fired and

coal-fired, but the data are nonetheless useful for estimating the

potential economic impact of the rule on small entities in terms of

cost-to-sales ratio. This analysis estimates costs as a percent of

value of shipments (closely related to sales) for affected facilities.

The average control cost as a percentage of value of shipments for all

affected facilities is 0.07 percent. The range of average control cost

across industries varies from a low of 0.004 percent for primary metals

to a high of 0.8 percent for the paper industry. Although the cost

varies by industry, boiler size, and fuel, it is unlikely that any

affected small entities will have a control cost to sales ratio of

greater than one percent.

G. Executive Order 13045

Executive Order 13045 applies to any rule that EPA determines (1)

economically significant as defined under Executive Order 12866, and

(2) the environmental health or safety risk addressed by the rule has a

disproportionate effect on children. If the regulatory action meets

both criteria, the Agency 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 considered by the Agency.

This final rule is not subject to Executive Order 13045, entitled

Protection of Children from Environmental Health Risks and Safety Risks

(62 FR 19885, April 23, 1997), because it does not involve decisions on

environmental health risks or safety risks that may disproportionately

affect children.

H. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement

Act of 1995 (NTTAA) directs all Federal

[[Page 49453]]

agencies to use voluntary consensus standards instead of government-

unique standards in their regulatory activities unless to do so would

be inconsistent with applicable law or otherwise impractical. Voluntary

consensus standards are technical standards (e.g., material

specifications, test methods, sampling and analytical procedures,

business practices, etc.) that are developed or adopted by one or more

voluntary consensus standards bodies. Examples of organizations

generally regarded as voluntary consensus standards bodies include the

American Society for Testing and Materials (ASTM), the National Fire

Protection Association (NFPA), and the Society of Automotive Engineers

(SAE). The NTTAA requires Federal agencies like EPA to provide

Congress, through OMB, with explanations when an agency decides not to

use available and applicable voluntary consensus standards.

This action does not involve any new technical standards or the

incorporation by reference of existing technical standards. Therefore,

consideration of voluntary consensus standards is not relevant to this

action.

I. 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 this 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 rule in the Federal Register. This action is a

``major rule'' as defined by 5 U.S.C. 804(2).

J. Clean Air Act Procedural Requirements

1. Administrator's Listing--Section 111

As prescribed by section 111(b)(1)(A) of the Act, establishment of

standards of performance for electric utility steam generating units

and industrial-commercial-institutional steam generating units was

preceded by the Administrator's determination that these sources

contribute significantly to air pollution which may reasonably be

anticipated to endanger public health or welfare.

2. Periodic Review--Section 111

This regulation will be reviewed again 8 years from the date of

promulgation of these revisions to the standard. The review will

include an assessment of the need for integration with other programs,

enforceability, improvements in emission control technology, and

reporting requirements.

3. External Participation--Section 117

In accordance with section 117 of the Act, publication of this

review was preceded by consultation with independent experts. The

Administrator has considered comments on several aspects of the

proposed revisions, including economic and technical issues.

4. Economic Impact Analysis--Section 317

Section 317 of the Act requires the EPA to prepare an economic

impact assessment for any emission standards under section 111 of the

Act. An economic impact assessment was prepared for the proposed

revision to the standards. In the manner described above under the

discussions of the impacts of, and rationale for, the proposed revision

to the standards, the EPA considered all aspects of the assessments in

promulgating the revision to the standards. The economic impact

assessment is included in the docket listed at the beginning of this

document under SUPPLEMENTARY INFORMATION.

Statutory Authority

The statutory authority for this rule is provided by sections 101,

111, 114, 301, and 407 of the Clean Air Act, as Amended; 42 U.S.C.

7401, 7411, 7414, 7601, and 7651f.

List of Subjects in 40 CFR Part 60

Environmental protection, Air pollution control, Electric utility

steam generating units, Industrial-commercial-institutional steam

generating units, Intergovernmental relations, Reporting and

recordkeeping requirements.

Dated: September 3, 1998

Carol M. Browner,

Administrator.

For the reasons set out in the preamble, title 40, chapter 1 of the

Code of Federal Regulations is amended as follows.

PART 60--[AMENDED]

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

Authority: 42 U.S.C. 7401, 7411, 7413, 7414, 7416, 7601, and

7602.

Subpart Da--[Amended]

2. Section 60.40a is amended by revising paragraph (b) to read as

follows:

Sec. 60.40a Applicability and designation of affected facility.

* * * * *

(b) Unless and until subpart GG of this part extends the

applicability of subpart GG of this part to electric utility steam

generators, this subpart applies to electric utility combined cycle gas

turbines that are capable of combusting more than 73 megawatts (250

million Btu/hour) heat input of fossil fuel in the steam generator.

Only emissions resulting from combustion of fuels in the steam

generating unit are subject to this subpart.

(The gas turbine emissions are subject to subpart GG of this part.)

* * * * *

3. Section 60.41a is amended by adding a definition for ``Gross

output'' in alphabetical order to read as follows:

Sec. 60.41a Definitions.

* * * * *

Gross output means the gross useful work performed by the steam

generated. For units generating only electricity, the gross useful work

performed is the gross electrical output from the turbine/generator

set. For cogeneration units, the gross useful work performed is the

gross electrical output plus one half the useful thermal output (i.e.,

steam delivered to an industrial process).

* * * * *

4. Section 60.44a is amended by revising paragraphs (a)

introductory text and (c) introductory text and by adding paragraph (d)

to read as follows:

Sec. 60.44a Standard for nitrogen oxides.

(a) On and after the date on which the initial performance test

required to be conducted under Sec. 60.8 is completed, no owner or

operator subject to the provisions of this subpart shall cause to be

discharged into the atmosphere from any affected facility, except as

provided under paragraphs (b) and (d) of this section, any gases which

contain nitrogen oxides (expressed as NO2) in excess of the

following emission limits, based on a 30-day rolling average:

* * * * *

(c) Except as provided under paragraph (d) of this section, when

two or more fuels are combusted simultaneously, the applicable standard

is determined by proration using the following formula:

* * * * *

(d)(1) On and after the date on which the initial performance test

required to be conducted under Sec. 60.8 is completed,

[[Page 49454]]

no new source owner or operator subject to the provisions of this

subpart shall cause to be discharged into the atmosphere from any

affected facility for which construction commenced after July 9, 1997

any gases which contain nitrogen oxides (expressed as NO2)

in excess of 200 nanograms per joule 1.6 pounds per megawatt-hour)

gross energy output, based on a 30-day rolling average.

(2) On and after the date on which the initial performance test

required to be conducted under Sec. 60.8 is completed, no existing

source owner or operator subject to the provisions of this subpart

shall cause to be discharged into the atmosphere from any affected

facility for which modification or reconstruction commenced after July

9, 1997 any gases which contain nitrogen oxides (expressed as

NO2) in excess of 65 ng/JI (0.15 pounds per

million Btu) heat input, based on a 30-day rolling average.

5. Section 60.46a is amended by adding paragraph (i) to read as

follows:

Sec. 60.46a Compliance provisions.

* * * * *

(i) Compliance provisions for sources subject to Sec. 60.44a(d).

(1) The owner or operator of an affected facility subject to

Sec. 60.44a(d)(1) (new source constructed after July 7, 1997) shall

calculate NOX emissions by multiplying the average hourly

NOX output concentration measured according to the

provisions of Sec. 60.47a(c) by the average hourly flow rate measured

according to the provisions of Sec. 60.47a(1) and divided by the

average hourly gross heat rate measured according to the provisions of

Sec. 60.47a(k).

(2) The owner or operator of an affected facility subject to

Sec. 60.44a(d)(2) (modified or reconstructed source after July 7, 1997)

shall demonstrate compliance according to the provisions of paragraph

(g) of this section.

6. Section 60.47a is amended by revising paragraph (c) and by

adding paragraphs (k) and (l) to read as follows:

Sec. 60.47a Emission monitoring.

* * * * *

(c)(1) The owner or operator of an affected facility shall install,

calibrate, maintain, and operate a continuous monitoring system, and

record the output of the system, for measuring nitrogen oxides

emissions discharged to the atmosphere; or

(2) If the owner or operator has installed a nitrogen oxides

emission rate continuous emission monitoring system (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, that CEMS may be used

to meet the requirements of this section, except that the owner or

operator shall also meet the requirements of Sec. 60.49a. Data reported

to meet the requirements of Sec. 60.49a shall not include data

substituted using the missing data procedures in subpart D of part 75

of this chapter, nor shall the data have been bias adjusted according

to the procedures of part 75 of this chapter.

* * * * *

(k) The procedures specified in paragraphs (k)(1) through (k)(3) of

this section shall be used to determine gross heat rate for sources

demonstrating compliance with the output-based standard under

Sec. 60.44a(d)(1).

(1) The owner or operator of an affected facility with electricity

generation shall install, calibrate, maintain, and operate a wattmeter;

measure gross electrical output in megawatt-hour on a continuous basis;

and record the output of the monitor.

(2) The owner or operator of an affected facility with process

steam generation shall install, calibrate, maintain, and operate meters

for steam flow, temperature, and pressure; measure gross process steam

output in joules per hour (or Btu per hour) on a continuous basis; and

record the output of the monitor.

(3) For affected facilities generating process steam in combination

with electrical generation, the gross energy output is determined from

the gross electrical output measured in accordance with paragraph

(k)(1) of this section plus 50 percent of the gross thermal output of

the process steam measured in accordance with paragraph (k)(2) of this

section.

(l) The owner or operator of an affected facility demonstrating

compliance with the output-based standard under Sec. 60.44a(d)(1)

shall, install, certify, operate, and maintain a continuous flow

monitoring system, and record the output of the system, for measuring

the flow of exhaust gases discharged to the atmosphere.

7. Section 60.49a is amended by revising the first sentence of

paragraph (i) and adding paragraph (j) to read as follows:

Sec. 60.49a Reporting requirements.

* * * * *

(i) Except as provided in paragraph (j) of this section, the owner

or operator of an affected facility shall submit the written reports

required under this section and subpart A of this part to the

Administrator for every calendar quarter. * * *

(j) The owner or operator of an affected facility may submit

electronic quarterly reports for SO2 and/or NOX

and/or opacity in lieu of submitting the written reports required under

paragraphs (b) and (h) of this section. The format of each quarterly

electronic report shall be coordinated with the permitting authority.

The electronic report(s) shall be submitted no later than 30 days after

the end of the calendar quarter and shall be accompanied by a

certification statement from the owner or operator, indicating whether

compliance with the applicable emission standards and minimum data

requirements of this subpart was achieved during the reporting period.

Before submitting reports in the electronic format, the owner or

operator shall coordinate with the permitting authority to obtain their

agreement to submit reports in this alternative format.

Subpart Db--[Amended]

8. Section 60.40b is amended by adding paragraphs (h) and (i) to

read as follows:

Sec. 60.40b Applicability and delegation of authority.

* * * * *

(h) Affected facilities which meet the applicability requirements

under subpart Eb (Standards of performance for municipal waste

combustors; Sec. 60.50b) are not subject to this subpart.

(i) Unless and until subpart GG of this part is revised to extend

the applicability of subpart GG of this part to steam generator units

subject to this subpart, this subpart will continue to apply to

combined cycle gas turbines that are capable of combusting more than 29

MW (100 million Btu/hour) heat input of fossil fuel in the steam

generator. Only emissions resulting from combustion of fuels in the

steam generating unit are subject to this subpart. (The gas turbine

emissions are subject to subpart GG of this part.)

9. Section 60.44b is amended by revising paragraphs (a)

introductory text, (b) introductory text, (c), and (e) introductory

text and by adding paragraph (l) to read as follows:

Sec. 60.44b Standard for nitrogen oxides.

(a) Except as provided under paragraphs (k) and (l) of this

section, on and after the date on which the initial performance test is

completed or is required to be completed under Sec. 60.8 of this part,

whichever date comes first, no owner or operator of an affected

facility that is subject to the provisions of this section and that

combusts only coal, oil, or natural gas shall cause to be discharged

into the atmosphere from that affected facility any gases that

[[Page 49455]]

contain nitrogen oxides (expressed as NO2) in excess of the

following emission limits:

* * * * *

(b) Except as provided under paragraphs (k) and (l) of this

section, on and after the date on which the initial performance test is

completed or is required to be completed under Sec. 60.8 of this part,

whichever date comes first, no owner or operator of an affected

facility that simultaneously combusts mixtures of coal, oil, or natural

gas shall cause to be discharged into the atmosphere from that affected

facility any gases that contain nitrogen oxides in excess of a limit

determined by the use of the following formula:

* * * * *

(c) Except as provided under paragraph (l) of this section, on and

after the date on which the initial performance test is completed or is

required to be completed under Sec. 60.8 of this part, whichever date

comes first, no owner or operator of an affected facility that

simultaneously combusts coal or oil, or a mixture of these fuels with

natural gas, and wood, municipal-type solid waste, or any other fuel

shall cause to be discharged into the atmosphere any gases that contain

nitrogen oxides in excess of the emission limit for the coal or oil, or

mixtures of these fuels with natural gas combusted in the affected

facility, as determined pursuant to paragraph (a) or (b) of this

section, unless the affected facility has an annual capacity factor for

coal or oil, or mixture of these fuels with natural gas of 10 percent

(0.10) or less and is subject to a federally enforceable requirement

that limits operation of the affected facility to an annual capacity

factor of 10 percent (0.10) or less for coal, oil, or a mixture of

these fuels with natural gas.

* * * * *

(e) Except as provided under paragraph (l) of this section, on and

after the date on which the initial performance test is completed or is

required to be completed under Sec. 60.8 of this part, whichever date

comes first, no owner or operator of an affected facility that

simultaneously combusts coal, oil, or natural gas with byproduct/waste

shall cause to be discharged into the atmosphere any gases that contain

nitrogen oxides in excess of the emission limit determined by the

following formula unless the affected facility has an annual capacity

factor for coal, oil, and natural gas of 10 percent (0.10) or less and

is subject to a federally enforceable requirement that limits operation

of the affected facility to an annual capacity factor of 10 percent

(0.10) or less:

* * * * *

(l) On and after the date on which the initial performance test is

completed or is required to be completed under Sec. 60.8 of this part,

whichever date comes first, no owner or operator of an affected

facility which commenced construction, modification, or reconstruction

after July 9, 1997 shall cause to be discharged into the atmosphere

from that affected facility any gases that contain nitrogen oxides

(expressed as NO2) in excess of the following limits:

(1) If the affected facility combusts coal, oil, or natural gas, or

a mixture of these fuels, or with any other fuels: A limit of 86 ng/

JI (0.20 lb/million Btu) heat input unless the affected

facility has an annual capacity factor for coal, oil, and natural gas

of 10 percent (0.10) or less and is subject to a federally enforceable

requirement that limits operation of the facility to an annual capacity

factor of 10 percent (0.10) or less for coal, oil, and natural gas; or

(2) If the affected facility has a low heat release rate and

combusts natural gas or distillate oil in excess of 30 percent of the

heat input from the combustion of all fuels, a limit determined by use

of the following formula:

En = [(0.10 * Hgo)+(0.20 * Hr)]/

(Hgo+Hr)

Where:

En is the NOX emission limit, (lb/million Btu),

Hgo is the heat input from combustion of natural gas or

distillate oil, and

Hr is the heat input from combustion of any other fuel.

10. Section 60.48b is amended by revising paragraph (b) to read as

follows:

Sec. 60.48b Emission monitoring for particulate matter and nitrogen

oxides.

* * * * *

(b) Except as provided under paragraphs (g), (h), and (i) of this

section, the owner or operator of an affected facility shall comply

with either paragraphs (b)(1) or (b)(2) of this section.

(1) Install, calibrate, maintain, and operate a continuous

monitoring system, and record the output of the system, for measuring

nitrogen oxides emissions discharged to the atmosphere; or

(2) If the owner or operator has installed a nitrogen oxides

emission rate continuous emission monitoring system (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, that CEMS may be used

to meet the requirements of this section, except that the owner or

operator shall also meet the requirements of Sec. 60.49b. Data reported

to meet the requirements of Sec. 60.49b shall not include data

substituted using the missing data procedures in subpart D of part 75

of this chapter, nor shall the data have been bias adjusted according

to the procedures of part 75 of this chapter.

* * * * *

11. Section 60.49b is amended by adding paragraph (v) to read as

follows:

Sec. 60.49b Reporting and recordkeeping requirements.

* * * * *

(v) The owner or operator of an affected facility may submit

electronic quarterly reports for SO2 and/or NOX

and/or opacity in lieu of submitting the written reports required under

paragraphs (h), (i), (j), (k) or (l) of this section. The format of

each quarterly electronic report shall be coordinated with the

permitting authority. The electronic report(s) shall be submitted no

later than 30 days after the end of the calendar quarter and shall be

accompanied by a certification statement from the owner or operator,

indicating whether compliance with the applicable emission standards

and minimum data requirements of this subpart was achieved during the

reporting period. Before submitting reports in the electronic format,

the owner or operator shall coordinate with the permitting authority to

obtain their agreement to submit reports in this alternative format.

[FR Doc. 98-24733 Filed 9-15-98; 8:45 am]

BILLING CODE 6560-50-P