[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
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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
[[Page 49443]]
F. Regulatory Flexibility Act
G. Executive Order 13045
H. National Technology Transfer and Advancement Act
I. Congressional Review Act
J. Clean Air Act Procedural Requirements
I. Background
A. Statutory and Regulatory Authority
Title IV of the Clean Air Act (the Act), as amended in 1990,
authorizes the EPA to establish an acid rain program to reduce the
adverse effects of acidic deposition on natural resources, ecosystems,
materials, visibility, and public health. The principal sources of the
acidic compounds are emissions of SO2 and NOX
from the combustion of fossil fuels. Section 407(c) of the Act requires
the EPA to revise standards of performance previously promulgated under
section 111 for NOX emissions from fossil-fuel fired steam
generating units, including both electric utility and nonutility units.
These revised standards of performance are to reflect improvements in
methods for the reduction of NOX emissions.
The current standards for NOX emissions from fossil-fuel
fired steam generating units, which were promulgated under section 111
of the Act, are contained in the new source performance standards
(NSPS) for electric utility steam generating units (40 CFR 60.40a,
subpart Da) and for industrial-commercial-institutional steam
generating units (40 CFR 60.40b, subpart Db).
B. Benefits of the NSPS Revisions
The revisions being promulgated reflect the Administrator's
determination that the best system of NOX emission reduction
(taking into consideration the cost of achieving such emission
reduction, any nonair quality health and environmental impact and
energy requirements) for these sources is now reflective of flue gas
treatment technologies, particularly selective catalytic reduction
(SCR). The estimated decrease in baseline nationwide NOX
emissions from new, reconstructed, or modified affected sources
resulting from these rule revisions remain unchanged since proposal and
are approximately 23,000 Mg/year (25,800 tons/year) from utility steam
generating units and 18,000 Mg/year (20,000 tons/year) from industrial
steam generating units in the 5th year after proposal. This represents
an approximate 42 percent reduction in the growth of NOX
emissions from new utility and industrial steam generating units
subject to these revised standards. This reduction in NOX
emissions benefits public health. Nitrogen oxides can cause lung tissue
damage, can increase respiratory illness, and are a primary contributor
to acid rain and ground level ozone formation. The Agency's estimate of
the other environmental, energy, cost, and economic impacts also are
unchanged since proposal. (See 62 FR 36957 for more information on
these estimates.)
In addition to direct environmental benefits, the EPA believes that
the output-based format of the final rule will contribute to important
national goals such as pollution prevention. One of the opportunities
for pollution prevention lies in simply using energy efficient
technologies to minimize the generation of emissions. These revisions
promote energy efficiency at utility plants by changing the manner in
which they regulate flue gas NOX emissions. The fuel neutral
format of the final rules also contributes to pollution prevention
opportunities by encouraging the use of clean fuels without limiting
the control options available for compliance.
A third major benefit of these revisions is that the final rules
reduce the reporting burden for units subject both to NSPS subpart Da
or Db and to other program(s) such as the Acid Rain or NOX
Budget Program. Therefore, the EPA will allow the SO2,
NOX, and opacity reports currently required under subpart Da
or Db to be submitted electronically in lieu of written reports. To
implement this electronic reporting option, special electronic data
report (EDR) record types would have to be created to accommodate the
compliance information required by subparts Da and Db, and sources
would be required to obtain an agreement from their EPA Regional office
and State authority to use the EDR format. The use of this report form
is optional.
C. Public Participation
Prior to proposal, the EPA met with industry representatives
several times to discuss the data and information used to develop the
proposed revisions. In addition, equipment vendors, State regulatory
authorities, and environmental groups had opportunity to comment on the
background information that was prepared for the proposed revisions. In
addition, representatives from other EPA offices and programs have been
included in the regulatory development process as members of the Work
Group.
The proposed revisions were published in the Federal Register on
July 9, 1997 (62 FR 36948). The preamble to the proposed revisions
discussed the availability of technical support documents, which
described in detail the information gathered during the standards
review. Public comments were solicited at proposal.
To provide interested persons the opportunity for oral presentation
of data, views, or arguments concerning the proposed standards, a
public hearing was held on August 8, 1997, at Research Triangle Park,
North Carolina. However, the four scheduled speakers decided to submit
written comments in place of attending the hearing, so no information
was presented at the hearing.
The original public comment period was from July 9, 1997 to
September 8, 1997. The EPA extended the public comment period to
October 8, 1997 based on requests from commenters. During the public
comment period, the EPA received 70 public comment letters on the
proposed rule changes. In the post-proposal period, the EPA met with
several industry representatives to learn more of their concerns
regarding the proposed revisions and to gather additional information
in order to respond to the public comments. Records of these contacts
are found in the final rulemaking docket. All of the comments have been
carefully considered, and, where determined to be appropriate by the
Administrator, changes have been made in the proposed standards based
on the comments received.
II. Summary of Final Rules
The final standards revise the NOX emission limits for
steam generating units in subpart Da (Electric Utility Steam Generating
Units) and subpart Db (Industrial-Commercial-Institutional Steam
Generating Units). Only those electric utility and industrial steam
generating units for which construction, modification, or
reconstruction is commenced after July 9, 1997 would be affected by
these revisions.
The NOX emission limit in the final rule for newly
constructed subpart Da units is 200 nanograms per joule (ng/
JO) (1.6 lb/megawatt-hour (MWh)) gross energy output
regardless of fuel type. For existing sources that become subject to
subpart Da through modification or reconstruction, the NOX
emission limit is 65 ng/JI [0.15 pounds per million BTU (lb/
MMBtu)] heat input. For subpart Db units, the NOX emission
limit being promulgated is 87 ng/JI (0.20 lb/MMBtu) heat
input from the combustion of natural gas, oil, coal, or a mixture
containing any of these fossil fuels; however, for low heat release
rate units firing natural gas or distillate oil, the current
NOX emission limit of 43 ng/JI (0.10 lb/MMBtu)
heat input is unchanged.
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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