[Federal Register Volume 63, Number 179 (Wednesday, September 16, 1998)]
[Rules and Regulations]
[Pages 49442-49455]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-24733]



[[Page 49442]]

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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:

------------------------------------------------------------------------
                                                Examples of regulated   
                 Category                             entities          
------------------------------------------------------------------------
Industry..................................  Electric utility steam      
                                             generating units,          
                                             Industrial steam generating
                                             units, Commercial steam    
                                             generating units, and      
                                             Institutional steam        
                                             generating units.          
------------------------------------------------------------------------

    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

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    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.

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    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