[Federal Register Volume 62, Number 131 (Wednesday, July 9, 1997)]
[Proposed Rules]
[Pages 36948-36963]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-17950]
[[Page 36947]]
_______________________________________________________________________
Part III
Environmental Protection Agency
_______________________________________________________________________
40 CFR Part 60
Proposed Revision of Standards of Performance for Nitrogen Oxide
Emissions From New Fossil-Fuel Fired Steam Generating Units; Proposed
Revisions to Reporting Requirements for Standards of Performance for
New Fossil-Fuel Fired Steam Generating Units; Proposed Rule
Federal Register / Vol. 62, No. 131 / Wednesday, July 9, 1997 /
Proposed Rules
[[Page 36948]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[FRL-5854-5]
RIN-2060-AE56
Proposed Revision of Standards of Performance for Nitrogen Oxide
Emissions From New Fossil-Fuel Fired Steam Generating Units; Proposed
Revisions to Reporting Requirements for Standards of Performance for
New Fossil-Fuel Fired Steam Generating Units
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed revisions.
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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. This document presents EPA's findings and proposes
revisions to the existing NOX standards.
The proposed changes to the existing standards for NOX
emissions reduce the numerical NOX emission limits for both
utility and industrial steam generating units to reflect the
performance of best demonstrated technology. The proposal also changes
the format of the revised NOX emission limit for electric
utility steam generating units to an output-based format to promote
energy efficiency and pollution prevention.
As a separate activity, EPA has also reviewed the quarterly sulfur
dioxide, NOX, and opacity emission reporting requirements of
the utility and industrial steam generating unit regulations contained
in 40 CFR part 60, subpart Da and Db. This document proposes to 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: Comments. Comments on the proposed revisions must be received on
or before September 8, 1997.
Public Hearing. A public hearing will be held, if requested, to
provide interested persons an opportunity for oral presentations of
data, views, or arguments concerning the proposed revisions. If anyone
contacts the EPA requesting to speak at a public hearing by July 30,
1997, a public hearing will be held on August 8, 1997 beginning at 9:00
a.m. The public hearing is only for the oral presentations of comments
with the EPA asking clarifying questions. Persons interested in
attending the hearing should call Ms. Donna Collins at (919) 541-5578
to verify that a hearing will occur.
Request to Speak at Hearing. Persons wishing to present oral
testimony must contact EPA by July 30, 1997.
ADDRESSES: Interested parties may submit written comments (in duplicate
if possible) to 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, S.W., Washington, D.C. 20460.
The Agency requests that a separate copy also be sent to the contact
person listed below. 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.
Comments and data also may be submitted electronically by sending
electronic mail (e-mail) to: [email protected]. Electronic
comments must be submitted as an ASCII file avoiding the use of special
characters and any form of encryption. Comments and data also will be
accepted on disks in WordPerfect in 5.1 file format or ASCII file
format. All comments and data in electronic form must be identified by
the docket number A-92-71. No Confidential Business Information (CBI)
should be submitted through e-mail. Electronic comments on this
proposed rule may be filed online at many Federal Depository Libraries.
Public Hearing. If a public hearing is held, it will be held at
EPA's Office of Administration Auditorium, Research Triangle Park,
North Carolina. Persons wishing to present oral testimony should notify
Ms. Donna Collins, Combustion Group (MD-13), U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina 27711,
telephone number (919) 541-5578, FAX number (919) 541-5450.
Technical Support Documents. The technical support documents
summarizing information gathered during the review 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 or ``New Source Performance Standards, Subpart Db--
Technical Support for Proposed Revisions to NOX Standard'',
EPA-453/R-95-012.
Docket. Docket No. A-92-71, containing supporting information used
in developing the proposed revisions, is available for public
inspection and copying from 8:30 a.m. to 12:00 p.m. and 1:00 to 3:00
p.m., Monday through Friday, at EPA's Air Docket Section, Waterside
Mall, Room 1500, 1st Floor, 401 M Street, S.W., Washington, D.C. 20460.
A reasonable fee may be charged for copying docket materials, including
printed paper versions of electronic comments which do not include any
information claimed as CBI.
FOR FURTHER INFORMATION CONTACT: For information concerning specific
aspects of this proposal, 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.
SUPPLEMENTARY INFORMATION: The following outline is provided to aid in
locating information in this notice.
I. Background
II. Proposed Revisions
III. Rationale for Proposed Revisions
A. Performance of NOX Control Technology
B. Control Technology Costs
C. Regulatory Approach
D. Revised Standard for Electric Utility Steam Generating Units
(Subpart Da)
E. Revised Standard for Industrial-Commercial-Institutional
Steam Generating Units (Subpart Db)
F. Alternate Standard for Consideration
IV. Modification and Reconstruction Provisions
V. Summary of Considerations Made in Developing the Rule
VI. Summary of Cost, Environmental, Energy, and Economic Impacts
VII. Request for Comments
VIII. Administrative Requirements
This document is also available on the Technology Transfer Network
(TTN), one of the EPA's electronic bulletin boards. The TTN provides
information and technology exchange in various areas of air pollution
control. The service is free, except for the cost of a phone call. Dial
(919) 541-5742 for up to a 14,400 bps modem. The TTN is also accessible
via the Internet at ``ttnwww.rtpnc.epa.gov.'' If more information on
the TTN is needed, call the HELP line at (919) 541-5384.
[[Page 36949]]
I. Background
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 sulfur dioxide (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).
The current NOX standards for new utility steam
generating units were promulgated on June 11, 1979 (44 FR 33580). The
NSPS apply to electric utility steam generating units capable of firing
more than 73 megawatts (MW) (250 million Btu/hour) heat input of fossil
fuel, for which construction or modification commenced after September
18, 1978. The current NSPS also apply to industrial cogeneration
facilities that sell more than 25 MW of electrical output and more than
one-third of their potential output capacity to any utility power
distribution system. The current NOX standards for new
electric utility steam generating units are fuel-specific and were
based on combustion modification techniques. At the time the NSPS was
promulgated, the most effective combustion modification techniques for
reducing NOX emissions from utility steam generating units
were judged to be combinations of staged combustion [overfire air
(OFA)], low excess air (LEA), and reduced heat release rate.
The NSPS for NOX emissions for industrial steam
generating units was promulgated on November 25, 1986 (51 FR 42768).
The NSPS apply to industrial steam generating units with a heat input
capacity greater than 29 MW (100 million Btu/hour), for which
construction, modification, or reconstruction commenced after June 19,
1984. The NOX standards promulgated for industrial steam
generating units are fuel- and boiler-specific and were based on the
performance of LEA and LEA-staged combustion modification techniques.
II. Proposed Revisions
Standards of performance for new sources established under section
111 of the Act are to reflect the application of the best system of
emission reduction which (taking into consideration the cost of
achieving such emission reduction, any nonair quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated. This level of control is
commonly referred to as best demonstrated technology (BDT).
The proposed standards would 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 the
proposed revisions.
The NOX emission limit proposed in today's notice for
subpart Da units is 170 nanograms per joule (ng/J) [1.35 lb/megawatt-
hour (MWh)] net energy output regardless of fuel type. For subpart Db
units, the NOX emission limit being proposed is 87 ng/J
(0.20 lb/million Btu) heat input from the combustion of any gaseous
fuel, liquid fuel, or solid fuel; however, for low heat release rate
units firing natural gas or distillate oil, the current NOX
emission limit of 43 ng/J (0.10 lb/million Btu) heat input is
unchanged.
Compliance with the proposed NOX emission limit is
determined on a 30-day rolling average basis, which is the same
requirement as the one currently in subparts Da and Db.
The proposed revisions to the quarterly SO2,
NOX, and opacity reporting requirements of subparts Da and
Db would allow electronic quarterly reports to be submitted in lieu of
the written reports currently required under sections 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 consistent with
the electronic data reporting (EDR) format specified by the
Administrator under section 75.64(d) for use in the Title IV Acid Rain
Program. 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.
III. Rationale for Proposed Revisions
A. Performance of NOX Control Technology
The control technologies that are commercially available for
reducing NOX emissions can be grouped into one of two
fundamentally different techniques: combustion control and flue gas
treatment. Generally, combustion controls reduce NOX
emissions by suppressing NOX formation during the combustion
process. Flue gas treatment controls are add-on controls that reduce
NOX emissions after combustion has occurred.
Combustion control techniques generally employed on wall-fired
pulverized coal (PC) fired units include low NOX burners
(LNB) (i.e., burners that incorporate LEA and air staging within the
burner) or LNB with OFA. For tangentially-fired PC units, combustion
control techniques generally employed include LNB (i.e., a low
NOX configured coal and air nozzle array and injection of a
portion of the combustion air through air nozzles above, but
essentially within the same waterwall hole as the coal and air nozzle
array) or LNB with separated OFA (i.e., LNB with additional air nozzles
above but outside the waterwall hole that includes the coal and air
nozzle array). For control of fluidized bed combustion (FBC) and stoker
steam generating units, air staging is the form of combustion control
employed.
Another group of combustion control techniques are based on the use
of clean fuels (i.e., natural gas). Commercially available gas-based
control techniques are reburning and cofiring with coal or oil. In
reburning, natural gas is injected above the primary combustion zone to
create a fuel-rich zone to reduce burner-generated NOX to
molecular nitrogen (N2) and water vapor. It is necessary to
add overfire air above the reburning zone to complete combustion of the
reburning fuel. Natural gas cofiring consists of injecting and
combusting natural gas near or concurrently with the main oil or coal
fuel.
Two commercially available flue gas treatment technologies for
reducing NOX emissions from fossil fuel-fired steam
generating units are selective noncatalytic reduction (SNCR) and
[[Page 36950]]
selective catalytic reduction (SCR). In SNCR, ammonia (NH3)
or urea is injected into the flue gas to reduce NOX to
N2 and water. The SCR utilizes injection of NH3
into the flue gas in the presence of a catalyst. The catalyst promotes
reactions that convert NOX to N2 and water at
higher removal efficiencies and lower flue gas temperatures than
required for SNCR.
Application of flue gas treatment technologies on coal-fired
boilers in the United States (U.S.) has grown considerably during the
past two years. However, both SNCR and SCR technologies have been
applied widely to commercial-scale gas-and oil-fired steam generating
units. Both technologies have been applied to coal-fired steam
generating units outside the U.S. The SCR technology has been
implemented on coal-fired steam generating units in Germany and Japan
over the past 15 years and has achieved substantially reduced
NOX emission levels. A recent EPA report notes that there
are 72 coal-fired plants (137 units) in Germany, 28 coal-fired plants
(40 units) in Japan, 9 coal-fired plants (29 units) in Italy, and 8
coal-fired plants (10 units) in other European countries using SCR (See
EPA report, ``Performance of SCR Technology for NOX
Emissions at Coal-Fired Electric Utility Units in the United States and
Western Europe'').
The SCR technology is currently being applied on seven coal-fired
steam generating units in the U.S. These applications are described in
Table 1.
Table 1.--Full-Scale SCR Experience on Coal-Fired Units in the U.S.
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Size Year
Plant, Unit No., and State (MWe) online
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Birchwood 1, VA....................................... 245 1996
Carney's Point 1, NJ.................................. 140 1994
Carney's Point 2, NJ.................................. 140 1994
Indiantown, FL........................................ 370 1996
Logan 1, NJ........................................... 230 1994
Merrimack 2, NH....................................... 320 1995
Stanton 2, FL......................................... 460 1996
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The SNCR technology has been applied in the U.S. to a number of
coal-fired utility and industrial steam generating units. Each of these
control technologies is discussed in the technical support documents.
The performance of combustion controls applied to subpart Da coal-
fired steam generating units was evaluated through statistical analyses
of continuous emission monitoring (CEM) data obtained from operators of
conventional and FBC electric utility steam generating units. The
objective of the analyses was to assess long-term NOX
emission levels that can be achieved continuously using combustion
controls. For the data analyses, individual steam generating units were
selected to represent the primary coal types and furnace configurations
(PC and FBC) used in this source category. The procedures used to
select individual steam generating units for statistical analyses, the
statistical analyses that were performed, and the results of the
statistical analyses for six sets of data reflecting recent operating
experience for subpart Da units using combustion controls are described
in the technical support document for the subpart Da revision. The
results indicate that the achievable NOX emissions from each
steam generating unit are lower than the current standard.1
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\1\ It should be noted that CEM data submitted to EPA under 40
CFR part 75 were not available during the development of the
technical support document. However, a preliminary examination of
these data shows that the average 30-day rolling NOX
emission rates were as low as 0.22 lb/million Btu heat input from
conventional PC units applying only LNB.
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The performance of combustion controls applied to stoker coal-fired
steam generating units was not evaluated using a detailed statistical
analyses of CEM data. However, long-term NOX emission data
obtained from four subpart Da stoker units with combustion controls
(i.e., air staging) were typically between 0.48 and 0.53 lb/million Btu
heat input. In stoker steam generating units, a minimum amount of
undergrate air must be used to provide adequate mixing and cooling.
Since the use of air staging reduces undergrate air flow, there may be
a limit to the degree of air staging used in stoker units and
consequently to the NOX reduction that can be achieved.
A statistical analysis of combustion controls applied to gas-and
oil-fired utility steam generating units was also not performed since:
(1) there are no known operating subpart Da natural gas-or oil-fired
utility units; (2) there are pre-NSPS utility steam generating units
burning these fuels that have been retrofit with combustion controls,
but long-term CEM data for these units were unavailable during the
development of the technical support document.
The NOX control performances of both flue gas treatment
technologies (i.e., SNCR and SCR) were evaluated based on short-term
test data from retrofit installations and permitted conditions for new
units. Long-term CEM data were used to evaluate SNCR for FBC boilers
and SCR for pulverized coal-fired units. The flue gas treatment
NOX control technology currently receiving the most
attention in the U.S. is SCR for conventional coal-fired utility steam
generating units.
Short-term test results of SNCR applied to fossil-fuel fired
utility boilers were obtained on 2 conventional coal-fired, 7 FBC, 2
oil-fired, and 10 gas-fired applications. For the conventional coal-
fired units, the NOX reductions varied from 30 to 60 percent
at full load, with NOX emission levels from 0.5 to 0.76 lb/
million Btu. These units were originally uncontrolled pre-NSPS units.
The NOX emissions from the seven FBC units ranged from 0.03
to 0.1 lb/million Btu at full load conditions. For oil-fired units, the
NOX emissions varied from 0.14 to 0.17 lb/million Btu,
depending on the NH3/NOX ratio. This corresponds
to NOX removal efficiencies of 48 to 56 percent from
uncontrolled levels. For gas-fired boilers, NOX emissions
ranged from 0.07 to 0.10 lb/million Btu at full load conditions or
about 10 to 40 percent reduction in NOX emissions. One
utility company reported information on the retrofit of 16 gas/oil-
fired steam generating units indicating a 25 to 30 percent reduction in
NOX emissions from combustion-controlled levels.
For evaluating the performance of SCR, short-term test results were
obtained from pilot-scale installations at two coal-fired and one oil-
fired steam generating unit, and from commercial-scale installations at
two coal-fired and two gas-fired steam generating units. Permitted
conditions for six new coal-fired facilities and two new gas-fired
facilities equipped with SCR systems also were obtained. In addition,
long-term CEM NOX emission data for full-scale SCR
applications at five pulverized coal-fired units with SCR were
obtained. To date, EPA is not aware of any full-scale SCR applications
on oil-firing steam generating units in the U.S.
For the pilot-scale coal-fired demonstrations, the project results
indicate that 75 to 80 percent NOX reductions from
uncontrolled levels were achieved.
Commercial-scale SCR installations on coal-fired units currently
operating in the U.S. are designed for NOX reductions
between 50 and 63 percent from combustion control levels, with design
and permitted NH3 slip levels (i.e., amount of unreacted
NH3 in exhaust gas) of 5 ppm or less. Short-term test
results obtained from new installations range from 0.10 to 0.15 lb/
million Btu. The long-term CEM data obtained from two of these coal-
fired units have been evaluated using statistical analyses. The results
indicate
[[Page 36951]]
that the estimated achievable NOX emission rate from both
units is 0.142 lb/million Btu heat input, on a 30-day rolling average
basis. Further, the EPA recently analyzed long-term CEM data from five
new U.S. coal-fired units. All units operated below their permitted
NOX emission levels, which were no greater than 0.17 lb/
million Btu (EPA report ``Performance of Selective Catalytic Reduction
Technology for NOX Emissions at Coal-Fired Electric Utility
Units in the United States and Western Europe''). Currently, EPA does
not have CEM data available for a coal-fired U.S. unit that just
started up (Birchwood Unit 1). However, in a recent public forum (cite:
presentation by David Gallaspy, VP Asia Pacific Rim, Southern Electric
International, at the 5th Annual CCT Conference, Tampa, Florida, Jan.
7-10, 1997) the operating utility stated that this unit is achieving
0.15 to 0.16 lb/million Btu with combustion controls alone and 0.07 to
0.08 lb/million Btu with the addition of SCR.
Permitted NOX emission levels (30-day rolling average)
for new coal-fired utility steam generating units equipped with SCR
typically range from 0.15 lb/million Btu for pulverized coal-fired
units to 0.25 lb/million Btu for stoker units.
For gas-fired steam generating units equipped with SCR, no
permitted NOX emission levels were available for gas-fired
utility steam generating units equipped with SCR; however, permitted
NOX levels range from 0.01 to 0.03 lb/million Btu for new
gas-fired industrial steam generating units equipped with SCR. No
permitted NOX levels were available for new oil-fired steam
generating units, either utility or industrial, equipped with SCR.
B. Control Technology Costs
The annualized costs and cost effectiveness of the NOX
control options for utility steam generating units are given in Table
2. The cost algorithms and assumptions used to estimate capital and
annualized costs and the model boilers developed for analyses are
described in the technical support documents.2 (For SCR and
SNCR costs, refer to the Draft Technical Report ``Cost Estimates for
Selected Applications of NOX Control Technologies on
Stationary Combustion Boilers,'' March 1996.)
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\2\ Note that updated costs of SNCR and SCR applications have
been presented in the document ``Cost Estimates for Selected
Applications of NOX Control Technologies on Stationary
Combustion Boilers,'' March 1996. These updated costs are shown in
Table 2.
Table 2.--Annualized Costs and Incremental Cost Effectiveness (Over the Baseline) of NOX Controls on Utility Steam Generating Units
[1995 Dollars] 1
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SNCR SCR
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Steam generating unit type Total annualized Total annualized
costs (mills/ Cost effectiveness ($/ costs (mills/ Cost effectiveness ($/
kwh) ton NOX removed) kwh) ton NOX removed)
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Gas............................................................. 0.5-0.8 1,600-3,100 0.55-1.1 1,400-2,700
Oil............................................................. 0.7-1.0 1,150-1,600 0.95-1.7 1,550-2,700
Coal............................................................ 1.2-1.7 1,170-1,630 2.1-3.3 1,460-2,270
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\1\ In Table 2, the SNCR and SCR costs are for applications on wall-fired boilers, designed to achieve a NOX emission limit of 0.15 lb/million Btu. The
baseline NOX levels used in determining the cost-effectiveness estimates were: (1) 0.45 lb/million Btu for coal-fired boilers, (2) 0.25 lb/million Btu
for gas-fired boilers, and (3) 0.30 lb/million Btu for oil-fired boilers.
The costs are presented in ranges to reflect the range of sizes
(100 to 1,000 MW) of the modeled units. The costs presented are based
on a capacity factor of 0.65. The costs for SNCR and SCR with
combustion controls are for retrofit installations and these costs for
new boilers might be lower than the costs shown in Table 2. (It is not
expected that gas- and oil-fired units would utilize SCR to meet the
proposed revised standards and, thus, these units would not incur the
costs associated with SCR use.) The cost effectiveness listed for each
control option represents the incremental cost-effectiveness of
applying that technology over the baseline (i.e., NOX levels
being achieved with technologies installed to meet the current NSPS).
The main differences between industrial steam generating units and
utility steam generating units are that industrial steam generating
units tend to be smaller and tend to operate at lower capacity factors.
The differences between industrial and utility steam generating units
would be reflected in the cost impacts of the various NOX
control technologies. Smaller sized and lower capacity factor units
tend to have higher cost on a per unit output basis. The annualized
costs and cost effectiveness of the NOX control options,
based on a model boiler analysis, for industrial steam generating units
are given in Table 3.
Table 3.--Annualized Costs and Incremental Cost Effectiveness (Over the Baseline) of NOX Controls of Industrial Steam Generating Units
[1995 Dollars]
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SNCR SCR
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Fuel type Annualized costs Annualized costs
(expressed as % Cost effectiveness ($/ (expressed as % Cost effectiveness ($/
of steam costs) ton NOX removed) of steam costs) ton NOx removed)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gas/Distillate Oil.............................................. 1.5-47.3 3,400-95,300 5.4-108.5 6,200-147,900
Residual Oil.................................................... 2.2-47.5 1,080-23,700 6.6-113.0 2,500-43,100
Coal............................................................ 1.9-15.2 550-4,710 10.3-45.2 1,590-8,700
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[[Page 36952]]
The costs are presented in ranges to reflect the range of sizes
(100 to 1,000 million Btu per hour) and capacity factors (0.1 to 0.6)
of the modeled units. The cost effectiveness listed for each control
option represents the incremental cost-effectiveness of applying that
technology over the baseline (i.e., NOX levels being
achieved with technologies installed to meet the current NSPS).
C. Regulatory Approach
In selecting a regulatory approach for formulating revised
standards to limit NOX emissions from new fossil fuel fired
steam generating units, the performance and cost of the NOX
control technologies discussed above were considered. The technical
basis selected for establishing revised NOX emission limits
is the performance of SCR (in combination with combustion controls).
The regulatory approach adopted to revise the current fuel/boiler-
specific standards would establish for both utility and industrial
steam generating units one emission standard which would be based on
the performance of SCR on coal-fired units in combination with
combustion controls. This uniform standard would be applicable
regardless of fossil fuel type or boiler type.
This regulatory approach differs from the historical approach to
establishing NOX emission limits for fossil fuel-fired steam
generating units, in which different emission limits are developed for
different combinations of fuel (gas, oil, coal) and boiler types, based
on the performance of a particular control technology applied to each
fuel/boiler type combination. The current subparts Da and Db standards
for NOX emissions are based on this approach. Under this new
regulatory approach, the focus is on controlling NOX
emissions from the generation of electricity or steam based on BDT
without regard to specific type of steam generating equipment. This
approach provides an incentive to consider both fuel/boiler type
combination and control technology when developing a NOX
control strategy. Since the basis selected for the revisions is the
high NOX removal performance of SCR, the relationship
between boiler NOX emissions and boiler design, fuel, and
operation is of lesser concern than if the basis was the performance of
combustion controls. Under the Clean Air Act Amendments of 1990, the
definition of ``Best Available Control Technology'' was revised to
include clean fuels. The definition of ``continuous system of emission
reduction'' under section 111 also allows EPA to consider clean fuels
because the term includes any process for production or operation of
any source which is inherently low polluting or non-polluting. Under
this regulatory approach, an emission limit is developed based on the
performance of the cleanest fuel so long as there is a technology which
allows other fuels to comply with that limit while providing cost-
effective NOX reductions. This approach addresses the
primary regulatory concern, NOX, but also can result in
lower carbon dioxide (CO2), air toxics, particulate, and
SO2 emissions, as well as lower solid waste and waste water
discharges.
The EPA's analysis shows that SCR can reduce NOX
emissions from coal-fired units to 0.15 lb/million Btu heat input. For
oil-fired units, SNCR in combination with combustion controls would be
able to achieve this NOX level. New gas-fired units may
require some degree of SNCR if improved combustion controls alone are
unable to achieve this level.
In light of the cost considerations associated with the application
of flue gas treatment over the range of industrial gas-fired and
distillate oil-fired units, a higher uniform NOX emission
limit of 0.20 lb/million Btu heat input was selected for industrial
steam generating units. Under EPA's regulatory approach, new gas-fired
and distillate oil-fired units would not require any additional
controls over those required under the current NSPS. Based on EPA's
cost impact analysis, it is estimated that by establishing the
NOX level at 0.20 lb/million Btu rather than at 0.15 lb/
million Btu, the annual nationwide control costs for new industrial
steam generating units will be reduced substantially, about 70 percent,
since the revision would result in no additional controls on gas-and
distillate oil-fired units. Since these gas and distillate oil-fired
units tend to be smaller in size and operated at lower capacity factors
than coal-fired industrial units, they tend to have much higher cost-
effectiveness values associated with the application of flue gas
treatment than do coal-fired units.
The single emission limitation approach would 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.
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.
Summary of Analyses. In order to determine the appropriate form and
level of control for the proposed revisions, EPA performed extensive
analyses of the potential national impacts associated with the revised
standards. These analyses examined the potential incremental national
environmental and cost impacts resulting from EPA's regulatory approach
in the fifth year following proposal of the revised standards. The
environmental impacts of the revised standards were examined by
projecting NOX emissions for each planned utility boiler and
industrial boiler. The cost impact analysis of the regulatory approach
included an estimation of the unit capital expenditures for air
pollution control equipment, as well as operating and maintenance
expenses associated with the equipment. These costs were examined both
in terms of annualized costs and percent of boiler output. The
regulatory approach also was examined in terms of cost per ton of
NOX removed.
The regulatory baseline used for the national impact analyses
consists of permitted levels for the planned utility steam generating
units and the existing NSPS applicable to industrial steam generating
units (i.e., subpart Db). The projected 5-year utility boiler
population was based on information obtained from two published reports
which list planned utility units. Utility owners and regulatory
agencies were contacted to update these projections and to determine
the permitted NOX emission levels for these units. It is
estimated that a total of 17 new boilers will be built over the 5-year
period, which would become subject to the revised subpart Da
NOX standard. For the industrial boiler category, sales data
and projected growth rates were used to estimate the number, capacity,
fuel type, and capacity factor of the industrial units expected to be
built during a 5-year period. The analysis projects that 381 new
industrial steam generating units will be constructed over the 5-year
period under the regulatory baseline. This projected total would
consist of 293 natural gas-or distillate oil-fired units, 66 residual
oil-fired units, and 22 coal-fired units.
Shown in Table 4 are the annualized costs, NOX reduction
(tons/year), and cost effectiveness ($/ton of NOX removed)
for the utility and industrial steam generating units regulated under
EPA's regulatory approach. Note that the cost effectiveness is the
average
[[Page 36953]]
incremental costs per ton of NOX removed over the baseline
(i.e., current NSPS). The cost effectiveness is determined by dividing
the change in annualized cost by the change in annual emissions, as
compared to the current standards.
Table 4.--Summary of National Impacts for Utility and Industrial Steam Generating Units
----------------------------------------------------------------------------------------------------------------
Utility Industrial
steam steam
Impacts Units generating generating
units units
----------------------------------------------------------------------------------------------------------------
Annualized Costs:
Total..................................... $million/year......................... 40 41
Range..................................... % of boiler output.................... 0-4.3 0-11.8
Average................................... % of boiler output.................... 2.0 1.8
NOX Reduction................................. Tons/year............................. 25,840 19,980
Cost Effectiveness:
Range..................................... $/Ton NOX Removed..................... 0-3,240 0-4,800
Average................................... $/Ton NOX Removed..................... 1,510 2,030
----------------------------------------------------------------------------------------------------------------
As shown in Table 4, under EPA's regulatory approach, national
NOX emissions would be reduced by about 41,560 megagrams
(Mg) (45,800 tons) per year. These NOX reductions on utility
and industrial units will be obtained at an average cost effectiveness
of about $1,770/ton of NOX removed.
D. Revised Standard for Electric Utility Steam Generating Units
(Subpart Da)
All known operating utility steam generating units currently
subject to subpart Da are coal-fired and use some form of combustion
control to comply with applicable emission limits. However, six
recently installed conventional PC units and some FBC units use add-on
NOX controls. Most new electric utility steam generating
units are projected to burn coal. Consequently, the NOX
studies used to develop the proposed revision have concentrated on the
combustion of coal.
The current NOX standards for subpart Da were based on
combustion control techniques and are fuel-specific. When these limits
were promulgated in 1979, the most effective combustion control
techniques for reducing NOX emissions from utility steam
generating units were judged to be combinations of staged combustion,
LEA, and reduced heat release rate.
Currently, SCR is considered to be the most effective
NOX control technology for new electric utility steam
generating units. Based on available performance data and cost
analyses, the Administrator has concluded that the application of SCR
represents the best demonstrated system of continuous emission
reduction (taking into consideration the cost of achieving such
emission reduction, any nonair quality health and environmental impact,
and energy requirements). Consequently, SCR was chosen as the basis for
revising the NOX emission limits due to its relatively high
NOX removal efficiency.
The national average cost effectiveness of additional
NOX control under this regulatory approach is about $1,500/
ton NOX removed. Further, under EPA's regulatory approach,
the cost of the installation and operation of the additional
NOX control equipment does not result in any significant
adverse economic impacts.
A benefit associated with the use of EPA's regulatory approach as
the basis for the revised NOX standard is that the approach
expands 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) can be a method of
achieving cost effective emission reductions from these coal-fired
steam generating units.
Based on available performance data and cost analyses, the
Administrator is proposing today a revised NOX emission
limit for electric utility steam generating units that applies
regardless of fuel type and which is based on coal-firing and the
performance of SCR control technology in combination with combustion
controls. The analysis shows that SCR can reduce NOX
emissions from coal-fired units to 0.15 lb/million Btu heat input or
less. This NOX emission level reflects about a 75 percent
reduction in NOX emissions over the current subpart Da
limits for coal-fired units. This NOX emission level also
reflects about a 50 and 25 percent reduction in NOX
emissions over the current subpart Da limits for oil-fired and gas-
fired units, respectively.
Regarding the revised NOX emission limitation, the
Administrator sought to achieve the best balance between control
technology and environmental, economic, and energy considerations. In
selecting a single emission limitation for electric utility steam
generating units that would be applicable regardless of fuel type, the
Administrator sought not to limit the control options available for
compliance, but to provide flexibility for cheaper and less energy
intensive control technologies (i.e., by allowing the use of clean
fuels for reducing NOX emissions). Available gas-based
control techniques are cofiring with coal or oil, reburning, and
switching to gas as the principal fuel. The clean fuel approach fits
well with 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 would be viewed as a sound alternative to flue
gas treatment technologies for coal or oil burning.
The fuel cost differential between gas and coal is one of the main
concerns with the application of gas-based technologies for the
reduction of NOX from coal-fired boilers. Access to gas
supply (proximity to pipeline) and long-term gas availability are
additional concerns that may limit natural gas use solely for
NOX control. Therefore, selection of SCR in combination with
combustion controls as the basis for the proposed revised
NOX limitation is appropriate since this technology is
expected to be an important part of the compliance mix for coal-fired
boilers. Again, for new oil-fired units, SNCR in combination with
combustion controls would be able to achieve the proposed limit. New
gas-fired units may require some degree of SNCR if improved combustion
controls alone are unable to achieve the revised limitation which
reflects a 25 percent reduction in NOX emissions over the
current NOX standard for gas-fired utility units.
[[Page 36954]]
Output-Based Format. The EPA has established pollution prevention
as one of the its highest priorities. One of the opportunities for
pollution prevention lies in simply using energy efficient technologies
to minimize the generation of emissions. The EPA investigated ways to
promote energy efficiency in utility plants by changing the manner in
which it regulates flue gas NOX emissions (see EPA white
paper, ``Use of Output-based Emission Limits in NOX
Regulations''). Therefore, in an effort to promote energy efficiency in
utility steam generating facilities, the Administrator is proposing an
output-based standard, which is a revised format, for subpart Da.
Traditionally, utility NOX emissions have been
controlled on the basis of boiler input energy (lb of NOX/
million Btu heat input). However, input-based limitations allow units
with low operating efficiency to emit more NOX per megawatt
(MWe) of electricity produced than more efficient units. Considering
two units of equal capacity, under current regulations, the less
efficient unit will emit more NOX because it uses more fuel
to produce the same amount of electricity. One way to regulate mass
emissions of NOX and plant efficiency is to express the
NOX emission standard in terms of output energy. Thus, an
output-based emission standard would provide a regulatory incentive to
enhance unit operating efficiency and reduce NOX emissions.
Two of the possible output-based formats considered for the revised
NOX standard were: (1) mass of NOX emitted per
gross boiler steam output (lb NOX/million Btu heat output),
and (2) mass of NOX emitted per net energy output [lb
NOX/megawatt-hour(MWh)]. The criteria used for selecting the
format were ease in monitoring and compliance testing and ability to
promote energy efficiency.
The objective of an output-based standard is to establish a
NOX emission limit in a format that incorporates the effects
of plant efficiency. Additionally, the limit should be in a format that
is practical to implement. Thus, the format selected must satisfy the
following: (1) provide flexibility in promotion of plant efficiency;
(2) permit measurement of parameters related to stack NOX
emissions and plant efficiency, on a continuous basis; and (3) be
suitable for equitable application on a variety of power plant
configurations.
The option of lb NOX/million Btu steam output accounts
only for boiler efficiency and ignores both the turbine cycle
efficiency and the effects of energy consumption internal to the plant.
The boiler efficiency is mainly dependent on fuel characteristics.
Beyond the selection of fuels, plant owners have little control over
boiler efficiency. This option, therefore, does not meet the first
criterion, because it provides the owners with minimal opportunities
for promoting energy efficiency at their respective plants.
The second output-based format option of lb NOX/MWh net
meets all three criteria. In this case, the net plant energy output
represents the energy exported out of the plant to other sources. This
energy output takes into account all internal energy consumption and
losses for the plant. An emission limit based on this format,
therefore, provides the owners with all possible opportunities for
promoting energy efficiency at their respective plants. This option
would require continuous measurement of the mass rate of NOX
emissions and net plant energy output. The net energy output can
include both electrical and thermal (process steam) outputs. Both of
these energy outputs are relatively easy to measure accurately, and
currently are measured routinely in power plants. Further, since this
option does take into account the auxiliary power requirements, an
emission limit based on this format can be applied equitably on a
variety of power plant configurations.
Based on this analysis, an emission limit format based on mass of
NOX emissions per net plant energy output is selected for
the proposed output-based standard. Because electrical output, measured
directly in MW, is the main energy output at all power plants, it is
desirable to use a format in ``lb NOX/MWh net.'' The EPA,
however, requests comments on the selected format of ``lb
NOX/MWh net'' since a format of ``lb NOX/MWh
gross'' may be more equitable in light of the varying auxiliary power
requirements that may exist at power plants. At cogeneration plants,
energy output is associated with electricity and process steam;
however, the useful heat (Btu/hr) present in steam can be converted to
MW.
Compliance with the output-based emission limit would require
continuous measurement of plant operating parameters associated with
the mass rate of NOX emissions and net energy outputs. In
the case of cogeneration plants where process steam is an output
product, means would have to be provided to measure the process steam
flow conditions and to determine the useful heat energy portion of the
process steam that is interchangeable with electrical output.
Instrumentation already exists in power plants to conduct these
measurements since the instrumentation is required to support current
emission regulations and normal plant operation. Consequently,
compliance with the output-based emission limit is not expected to
require any additional instrumentation. A current federal regulation
(40 CFR Part 75) requires measurements of both NOX
concentration and flue gas flow rate (for calculating mass rate of
NOX emissions), whereas metering of net electrical output
must be provided to account for net electrical sendout from the plant.
Therefore, no additional instrumentation is required for conventional
utility applications to comply with the output-based emission limit.
However, additional signal input wiring and programming is expected to
be required to convert the above measurements into the compliance
format (lb NOX/MWh net).
For cogeneration units, steam is also generated for process use.
The energy content of this process steam also must be considered in
determining compliance with the output-based standard. This can be
accomplished by measuring the total heat content of each process steam
source (from the measured flow, pressure, and temperature) and then
calculating the useful energy output. If the equivalent electrical
energy (useful heat) content of the process steam is expressed in the
form of curves, no new instrumentation is required. The information
from these curves can be programmed into the plant monitoring system
and the equivalent electrical energy for each process steam source can
be calculated. This equivalent electrical energy (MW) can be added to
the plant's actual net electrical output (MW) to arrive at the plant's
total net energy output (MW). This total net energy output (MW) used
with the mass rate of NOX emissions (lb/h), yields the
NOX emissions (lb/MWh net) for compliance.
Since all the reported data obtained throughout the development of
the revised standards are in the current format of lb/million Btu heat
input, EPA applied an efficiency factor to the current format to
develop the output-based NOX limit. The efficiency factor
approach was selected because the alternative of converting all the
reported data in the database to an output-basis would require
extensive data gathering and analyses. Applying a baseline net
efficiency would essentially convert the selected heat input-based
NOX level to an output-based emission limit. The EPA
solicits comment on this format approach.
The output-based standard must be referenced to a baseline
efficiency. Most existing electric utility steam generating
[[Page 36955]]
plants fall in the range of 24 to 38 percent efficiency. However, newer
units (both coal- and gas-fired) operate around 38 percent efficiency;
therefore, 38 percent was selected as the baseline efficiency. The EPA
requests comment on: (1) whether 38 percent is an appropriate baseline
efficiency, (2) how often the baseline efficiency should be reviewed
and revised in order to account for future improvements in electric
generation technology, and (3) whether a 30-day rolling average is
sufficient to account for any operating efficiency variability.
The efficiency of electric utility steam generating units usually
is expressed in terms of heat rate, which is the ratio of heat input,
based on higher heating value (HHV) of the fuel, to the energy (i.e.,
electrical) output. The heat rate of a utility steam generating unit
operating at 38 percent efficiency is 9.5 joules per watt hour (9,000
Btu per kilowatt hour).
The efficiency of a steam generating plant refers to its net
efficiency. This is the net useful work performed divided by the fuel
heat input, taking into account the energy requirements for auxiliaries
(e.g., fans, soot blowers, pumps, fuel handling and preparation
systems) and emission control equipment. For conventional electric
utility units, the total useful work performed is the net electrical
output (i.e., net busbar power leaving the plant) from the turbine/
generator set. Determination of the net efficiency of a cogeneration
unit includes the net electrical output and the useful work achieved by
the energy (i.e., steam) delivered to an industrial process. Under a
Federal Energy Regulatory Commission (FERC) regulation, the efficiency
of cogeneration units is determined from ``* * * the useful power
output plus one half the useful thermal output * * *,'' 18 CFR Part
292, Sec. 205. Therefore, to determine the process steam energy
contribution to net plant output, a 50 percent credit of the process
steam heat was selected.
This proposed rulemaking does not include a specific methodology or
methodologies for determining the unit net output. The EPA intends to
specify such methods in the final rule. Consequently, the EPA requests
comment on: (1) the specific methodology or methodologies appropriate
and verifiable for determining the net output of a steam generating
unit; and (2) whether a fixed percentage credit of 50 percent is
representative of the useful heat in varying quality of process steam
flows. In addition, the EPA solicits comment on whether the output-
based standard in the proposed rule will promote energy efficiency
improvements. The EPA acknowledges that a supplemental notice may be
necessary should a specific methodology for determining the unit net
output be decided upon prior to finalizing this rule.
Based on the analysis showing that SCR can reduce NOX
emissions from coal-fired units to 0.15 lb/million Btu heat input or
less, the calculation of an equivalent output-based standard is
straight forward using the baseline net plant efficiency. The output-
based NOX standard is computed by using the following
equation:
EO(lb/MWh)=Ei(lb/million Btu) * n * 1000 kwh/MWh
Using an input-based emission level (Ei) of 0.15 lb/million Btu and
a baseline net efficiency (n) of 9,000 Btu/kwh, the resulting output-
based limit (EO) is 1.35 lb/MWh. Based on the available
performance data, cost analysis, and the above calculation, the
Administrator is proposing today a revised NOX emission
limit for new electric utility steam generating units of 1.35 lb of
NOX/MWh net.
E. Revised Standard for Industrial-Commercial-Institutional Steam
Generating Units (Subpart Db)
The NOX standard promulgated in 1986 for industrial
steam generating units is based on the performance of LEA and LEA-
staged combustion modification techniques. The NOX control
technology examined for revising the current NSPS is SCR in combination
with combustion controls. Currently, SCR is considered to be the most
effective NOX control technology for new industrial steam
generating units. Based on available performance data and cost
analyses, the Administrator has concluded that the application of SCR
represents the best demonstrated system of continuous emission
reduction (taking into consideration the cost of achieving such
emission reduction, any nonair quality health and environmental impact,
and energy requirements) for coal- and residual oil-fired industrial
steam generating units.
Under EPA's regulatory approach, the national average cost
effectiveness of additional NOX control is about $2,000/ton
NOX with a total nationwide increase in annualized costs of
about $40 million. Further, EPA's economic impacts analysis indicates
that revised standards based on the adopted regulatory approach would
increase product prices by less than 1 percent if all steam cost
increases were passed through to product prices. Consequently, the
economic impacts of standards based on EPA's regulatory approach are
not expected to be significant.
As discussed above for utility steam generating units, a benefit
associated with the selection of EPA's regulatory approach as the basis
for the revised NOX standard is that this regulatory
approach expands the control options available by allowing the use of
clean fuels as a method for reducing NOX emissions. The use
of clean fuels (i.e., natural gas) may be a cost-effective method of
reducing emissions from the coal- and residual oil-fired industrial
steam generating units.
Based on available performance data and cost analyses, the
Administrator is proposing a revised NOX emission limit for
industrial steam generating units which is applicable regardless of
fuel or boiler type, except for one boiler/fuel category. The proposed
revision is based on coal-firing and the performance of SCR control
technology in combination with combustion controls.
Regarding the revised NOX emission limitation for
industrial units, the Administrator again sought to achieve the best
balance between control technology and environmental, economic, and
energy considerations and not to limit the control options, but to
provide flexibility for cheaper and less energy-intensive control
technologies. Due to the cost considerations associated with the
application of flue gas treatment on the range of industrial gas-fired
and distillate oil-fired units, the Administrator is proposing for
industrial steam generating units a revised NOX emission
limit of 0.20 lb/million Btu heat input, except for the category of low
heat release rate units firing natural gas or distillate oil which
retains the current NOX emission limit of 0.10 lb/million
Btu heat input. The revised limit is the same as the current
NOX emission limit for the category of high heat release
rate units firing natural gas or distillate oil. Therefore, under the
revised limit, new gas- fired and distillate oil-fired units would not
require any additional controls over that required under the current
NSPS. Based on the cost impact analysis, it is estimated that by
establishing the revised limit at 0.20 lb/million Btu rather than at
0.15 lb/million Btu, the annual nationwide control costs for new
industrial steam generating units will be reduced substantially, about
70 percent lower, since the revision would result in no additional
controls on gas-and distillate oil-fired units. This revised limit
reflects about a 50 to 70 percent reduction in NOX emissions
over the
[[Page 36956]]
current subpart Db limits for coal-fired and residual oil-fired units.
For low heat release rate steam generating units firing fuel
mixtures that include natural gas or distillate oil, the NOX
emission limit would be determined by proration of the NOX
standards based on the respective amounts of each fuel fired when the
mixture contains more than 20 percent, based on heat input, of natural
gas or distillate oil. Low heat release rate steam generating units
firing fuel mixtures that include 20 percent or less of natural gas or
distillate oil are subject to the NOX emission limit of 0.20
lb/million Btu heat input since the use of natural gas or distillate
oil in these units is considered to be a clean fuel-based
NOX control technique.
Again, in selecting a single emission limitation that would be
applicable regardless of fuel type and boiler type, the Administrator
sought to expand the control options available by allowing the use of
clean fuels as a method for reducing NOX emissions. The use
of clean fuels (i.e., natural gas) as a method of reducing emissions
from these coal-fired and residual oil-fired industrial steam
generating units may be a cost-effective approach.
Because the fuel cost differential between gas and coal and access
to gas supply (proximity to pipeline) are concerns that may limit
natural gas use solely for NOX control, the control option
of SCR in combination with combustion controls that was selected as the
basis for the revised NOX limitation is appropriate since
this technology is expected to be an important part of the compliance
mix. For residual oil-fired units, SNCR in combination with combustion
controls would be able to achieve the proposed limit.
Consideration of an Output-Based Format. This proposed rulemaking
for industrial steam generating units does not include an output-based
format as is included in today's proposed NOX revision for
electric utility steam generating units. As stated in the discussion on
the proposed revision to the utility NSPS, the Administrator has
established pollution prevention as one of the EPA's highest
priorities. One of the opportunities for pollution prevention lies in
simply using energy efficient technologies to avoid generating
emissions. In an effort to promote energy efficiency in industrial
steam generating facilities, a revised output-based format for the
proposed NOX emission limit was investigated.
The two output-based formats considered were lb NOX/MWh
and lb NOX/million Btu steam output, the same formats
considered for utility steam generating units. The option of lb/MWh,
selected for utility units, is more easily understood for utility
applications generating only, or mostly, electricity but is
unreasonable for industrial units supplying only steam (no electricity
generation). The other output-based format option of lb/million Btu
steam output would be based on steam output from the boiler and could
be applicable to all new industrial boilers. However, this output-based
format option, as previously discussed, provides the owners with only
minimal opportunities for promoting energy efficiency at their
respective facilities. In addition, an output-based format would
require additional hardware and software monitoring requirements for
measuring the stack gas flow rate (for determining the mass rate of
NOX emissions), steam production rate, steam quality, and
condensate return conditions. Instrumentation to conduct these
measurements may not generally exists at industrial facilities as they
do at utility plants.
The EPA intends to continue to investigate appropriate output-based
formats for industrial units which would promote energy efficiency.
Consequently, the EPA requests comment on: (1) the specific methodology
or methodologies appropriate and verifiable for determining the net
energy output of an industrial steam generating unit, (2) the frequency
at which the unit's net output or efficiency should be documented, and
(3) whether an output-based standard for industrial steam generating
units will promote efficiency improvements.
F. Alternate Standard for Consideration
Because of the fundamental change in the format of the
NOX NSPS for electric utility units, the EPA anticipates
that there will be numerous concerns and comments concerning the
proposed output-based standard. Therefore, the Administrator is
proposing as an alternate to the output-based standard, a traditionally
formatted standard of 0.15 lb/million Btu heat input. This input-based
NOX level served as the basis for developing the output-
based standard being proposed today. The EPA's preference is to specify
an output-based standard in the final rule, but also is proposing the
input-based emission level as an alternate in case public comments and/
or findings warrant reconsideration of promulgating an output-based
standard. Therefore, the EPA also solicits comment on the input-based
emission level selected as the basis for the output-based standard,
which is achievable using SCR.
The majority of the electric utility steam generators regulated
under subpart Da are also regulated under the Title IV Acid Rain
Program of the Clean Air Act. The Acid Rain Continuous Emission
Monitoring Regulation (40 CFR part 75) requires affected units to
install, operate, maintain and quality-assure continuous monitoring
systems for SO2, NOX, flow rate, CO2,
and opacity. Section 75.64 of part 75 requires quarterly reporting of
SO2, NOX, and CO2 emissions in a
standardized EDR format specified by the Administrator. The EDR
reporting format has been used successfully for Acid Rain Program
implementation since 1994. The EDR data from calendar year 1995 were
used by the EPA to determine the compliance status of the Phase I-
affected Acid Rain units with respect to their allowable annual
SO2 emissions.
At the present time, there is an initiative underway in the Eastern
United States to establish an emission trading program for
NOX. The program is called the Ozone Transport Commission
(OTC) NOX Budget Program. Beginning in 1998, the largest
sources of NOX in 13 eastern States will be required to
account for their NOX emissions during the ozone season.
Many of the sources in the NOX Budget Program are electric
utility steam generators which are also regulated under NSPS subpart Da
and under 40 CFR part 75. Many other NOX Budget Program
sources are regulated under NSPS subpart Db. To implement the
NOX Budget Program, emission data from the affected sources
will be submitted electronically, in the EDR format specified under 40
CFR part 75.
At present, any Acid Rain-affected or NOX Budget
Program-affected steam generating unit which is also regulated under
NSPS subpart Da or Db must meet the reporting requirements of NSPS in
addition to the Acid Rain or NOX Budget Program reporting
requirements. For example, the owner or operator of a subpart Da
utility unit would have to submit written NSPS compliance reports each
quarter for SO2, NOX, and opacity, in addition to
the electronic report in EDR format required by part 75.
In many instances, the data reported to meet the requirements of
NSPS, the Acid Rain Program, and the OTC NOX Budget Program
are generated by the same CEM systems. The CEM data are manipulated in
different ways for the different programs, but very often the NSPS,
Acid Rain, and OTC reports are derived from the same data. In view of
[[Page 36957]]
this, EPA believes it is worthwhile to explore the possibility of
consolidating or streamlining the reporting requirements for steam
generating units subject to these programs.
The EPA has evaluated different ways in which the reporting burden
might be reduced for units subject both to NSPS subpart Da or Db and to
other program(s) such as the Acid Rain or NOX Budget Program
(see Docket Item #II-B-11; ``Assessment of Consolidating NSPS Subpart
Da and Part 75 Reporting Requirements;'' February 25, 1997). The Agency
has concluded that the best way to accomplish this would be to allow
the SO2, NOX, and opacity reports currently
required under subpart Da or Db to be submitted electronically in the
part 75 EDR format, in lieu of written reports. To implement this
electronic reporting option, special EDR record types would have to be
created to accommodate the compliance information required by subparts
Da and Db.
The EPA believes that in order to derive the full benefit from the
electronic reporting option in today's proposal, it should be made
available to all subpart Da and Db affected facilities, including units
presently regulated under those subparts, and including affected units
that are not regulated under part 75 or the NOX Budget
Program. Today's proposal, therefore, amends Secs. 60.49a and 60.49b to
allow the owner or operator of any subpart Da or Db facility to choose
the electronic reporting option.
IV. Modification and Reconstruction Provisions
Existing steam generating units that are modified or reconstructed
after today would be subject to today's revision and to the
requirements in the General Provisions (40 CFR 60.14 and 60.15), which
apply to all NSPS. Few, if any, changes typically made to existing
steam generating units would be expected to bring such steam generating
units under the proposed NOX revisions.
A modification is any physical or operational change to an existing
facility which results in an increase in emissions, 40 CFR Part 60,
Sec. 60.14. Changes to an existing facility which do not result in an
increase in emissions, either because the nature of the change has no
effect on emissions or because additional control technology is
employed to offset an increase in emissions, are not considered
modifications. In addition, certain changes have been exempted under
the General Provisions (40 CFR 60.14). These exemptions include
production increases resulting from an increase in the hours of
operation, addition or replacement of equipment for emission control
(as long as the replacement does not increase emissions), and use of an
alternative fuel if the existing facility was designed to accommodate
it, 40 CFR 60.14.
Rebuilt steam generating units would become subject to the proposed
NOX revision under the reconstruction provisions, regardless
of changes in emission rate, if the fixed capital cost of
reconstruction exceeds 50 percent of the cost of an entirely new steam
generating unit of comparable design and if it is technologically and
economically feasible to meet the applicable standard, 40 CFR 60.15.
V. Summary of Considerations Made in Developing the Rule
The Clean Air Act was created, in part, ``* * * to protect and
enhance the quality of the Nation's air resources so as to promote the
health and welfare and the productive capacity of its population * *
*'' As such, this regulation protects the public health by reducing
emissions of NOX from electric utility and industrial
facilities. 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 proposed revisions will substantially
reduce NOX emissions to the levels achievable using BDT.
The alternatives considered in the development of these proposed
revisions are based on emission and operating data received from
operating utility and industrial facilities and permitted information
for planned utility and industrial facilities. The EPA met with
industry representatives several times to discuss these data and
information. 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. Of
major concern to the industry was the actual numerical limits of the
revisions, and whether they would, in effect, dictate the use of only
one control option. By using a regulatory approach that expands
NOX control options, the EPA is proposing revised
NOX limits that address their concern.
Another major concern expressed by the utility industry was the
potential impact of the revision on existing utility units. Under the
General Provisions (40 CFR 60, subpart A) for standards of performance
for new stationary sources, an affected facility is defined as a unit
which commences construction, modification, or reconstruction after the
date of publication of the proposed rulemaking. To date, no existing
utility unit has become subject to subpart Da under either the
modification or reconstruction provision.
In the revisions, EPA has made an effort to minimize the impacts on
monitoring, recordkeeping, and reporting requirements. The proposal
does alter the monitoring and recordkeeping requirements (for
NOX only) currently listed in subpart Da by incorporating by
reference the monitoring provisions of the Acid Rain Regulation (40 CFR
parts 72, 73, 75, 77, and 78). However, 40 CFR part 75 already requires
new electric utility steam generating units to comply with these
monitoring requirements. In addition, requirements for monitoring of
net output, both electrical and process steam, is being added but these
are routinely measured by utility boiler owners and operators.
Accordingly, the averaging period (i.e., 30-day rolling average) and
reporting requirements of subpart Da are not being changed or replaced
by incorporating the monitoring provisions of the Acid Rain Regulation.
The proposal has no anticipated impact on monitoring, recordkeeping,
and reporting requirements for new electric utility steam generating
units. This proposal does not alter the monitoring, recordkeeping, or
reporting requirements currently listed in subpart Db.
Representatives from other EPA offices and programs are included in
the regulatory development process as members of the Work Group. The
Work Group is involved in the regulatory development process, and must
review and concur with the regulation before proposal and promulgation.
Therefore, the EPA believes that the implications to other EPA offices
and programs have been adequately considered during the development of
these revisions.
VI. Summary of Cost, Environmental, Energy, and Economic Impacts
The cost, environmental, energy, and economic impacts of the
proposed revisions are expressed as incremental differences between the
impacts of utility and industrial steam generating units complying with
the proposed revisions and these units complying with current emission
standards (i.e., subpart Da and Db or States' permitted limits).
The revised NOX standards may increase the capital costs
for new steam generating units because the implementation of either
SNCR or SCR requires additional hardware.
[[Page 36958]]
The EPA estimates that 17 new utility steam generating units and
381 new industrial steam generating units will be constructed over the
next 5 years and thus would be subject to the revised standards. The
nationwide increase in annualized costs in the 5th year following
proposal for the projected new electric utility steam generating units
subject to the revised standards is estimated to be about $40 million
for utility steam generating units. This impact assumes that all
planned coal-fired units remain coal-fired and employ SCR. This
represents an increase of about 1.3 mills/kwh in annual costs, or about
a 2 percent increase in the cost of generating electricity for these
units.
The nationwide increase in annualized costs for new industrial
steam generating units subject to the revised standards would be about
$41 million in the 5th year following proposal. This is based on the
assumption that no affected unit switches fuel type as the result of
the revision. This represents an average increase of about 2 percent in
the cost of producing steam for new units.
The cost effectiveness of the revised NOX standards over
the existing standards for electric utility units is projected to be
about $1,650/Mg ($1,500/ton) of NOX removed. For industrial-
commercial-institutional units, the cost effectiveness of the revised
NOX standards over the existing standards is projected to be
about $2,200/Mg ($2,000/ton) of NOX removed.
The primary environmental impact resulting from the revised
NOX standards is reductions in the quantity of
NOX emitted from new steam generating units subject to the
proposed revisions to the NSPS. Estimated baseline NOX
emissions from these new steam generating units are 39,500 Mg/year
(43,600 tons/year) from utility steam generating units and 58,400 Mg/
year (64,400 tons/year) from industrial steam generating units in the
5th year. The revised standards are projected to reduce baseline
NOX emissions by 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.
National secondary impacts for increased NH3 emissions
are estimated to be about 300 tons/year from utility steam generating
units and about 420 tons/year from industrial steam generating units
due to the NH3 slip from SCR or SNCR systems. Ammonia slip
tends to be higher from SNCR systems.
There are additional energy requirements associated with SCR
systems. Electrical energy is required for booster fans used to
overcome the pressure drop across the SCR reactor and related ductwork.
This energy requirement is estimated at about 0.4 percent of the boiler
output (and was not specifically incorporated into the determination of
the baseline operating efficiency of 38 percent).
The goal of the economic impact analysis was to estimate the market
response to the proposed changes to the existing standards for
NOX emissions for both utility and industrial steam
generating units. The analysis did not quantitatively address the
possibility of changing technology, fuel, or capacity utilization in
response to the proposed revisions. Therefore, costs and projected
impacts may be overestimated.
For utilities, cost estimates for affected facilities expected to
be built between 1996 and 2000 were used to project year by year price
and quantity changes. The price changes were estimated by assuming that
the production weighted average cost changes for the entire industry
are passed on to consumers. These estimates resulted in price increases
of between 0.01 percent in 1996 and 0.02 percent in 2000. Because the
demand for electricity is inelastic, these price changes are projected
to result in 0.002 percent (1996) and 0.004 percent (2000) decreases in
electricity sales. These numbers are quite small on an industry-wide
basis. The price changes on a facility basis, if the cost were
completely passed on to the consumer, would be as high as 6 percent; 9
of the 13 facilities would be 1 percent or less. Because the rate
structure of utilities generally has reflected the average costs for a
utility which includes multiple facilities, such a price increase is
unlikely. Therefore, the market impacts for electricity generation are
estimated to be small.
For industrial boilers, data by industry for fuel type, furnace
type, capacity, and capacity utilization were combined with projections
of boiler sales to estimate the number and type of boilers to be
replaced. The analysis assumes that a boiler will be replaced with a
boiler of the same fuel type, technology, capacity, and capacity
utilization. The analysis modeled the response of a firm faced with an
added pollution control cost for boiler replacement as a decision
concerning the timing of the replacement. The firm replaces an existing
boiler when operating costs have increased enough to make the
installation of a new boiler cheaper than continuing to operate the old
boiler. Added pollution control costs for a new boiler leads the firm
to defer the replacement of the existing boiler until the increased
cost of operation makes replacement even with the additional pollution
control costs the cheaper option. The average replacement delay was
very long for small, low-capacity utilization boilers requiring
control. Replacement delay may be viewed as an indicator of the
severity of impact. For these boilers, the assumption that they will be
replaced by a boiler of the same type, size, fuel type, and capacity
utilization is questionable in the absence of the proposed revision and
even more unlikely in the face of the proposed revision that would add
to the cost of small, low-capacity utilization boilers. For affected
boilers, the annual compliance cost as a share of annual steam costs
ranges from 3 percent for the largest high-capacity utilization
residual oil boiler to over 100 percent for the smallest low-capacity
utilization spreader stoker boilers.
For industrial boilers, net additions to steam capacity were also
estimated. The U.S. Department of Energy's Industrial Demand Module of
the National Energy Modeling System (NEMS) was used with U.S.
Department of Commerce projections to estimate steam demand through
2010. The yearly increase in demand for steam for each industry
corresponds to the required new steam generating capacity needed. The
new generating capacity is assumed to reflect estimates of the existing
distribution of boilers for that industry by fuel, furnace type,
furnace size, and capacity utilization. This leads to an estimate of
new capacity affected by the proposed changes in the standards, which
ranges from 45 percent for primary metals to 51 percent for paper. The
control costs are small for the affected portion of each industry
compared to the size of value of shipments for the affected portion.
These percentages range from 0.002 percent for miscellaneous
manufacturing to 0.8 percent for the paper industry.
The annualized social costs estimated in the economic impact
analysis include costs of more stringent control for projected new
utility boilers, industrial replacement boilers, and additions to
industrial boiler net capacity. For the utility boilers, the estimated
cost is $40 million which includes both the control cost ($39 million)
and a loss to consumers because of reduced electricity purchases ($1
million). The cost of replacing industrial boilers ($26
[[Page 36959]]
million) includes both the higher cost associated with delaying
replacement and the higher control cost after replacement. Estimated
control costs for projected net new boiler capacity is $49 million.
Because of the number of markets involved, no estimates of market
changes were made for industries affected by the proposed revision.
Therefore, the losses to consumers from reduced purchases of the final
goods due to increased costs of steam from industrial boilers were not
developed. The assumptions that replacement industrial boilers would be
the same as the boilers they replace in the absence of the proposed
revisions and that no affected boilers would respond to the proposed
revision by changing size, fuel, type, or capacity utilization of
affected boilers lead to higher cost estimates. Impacts on fuel markets
such as coal are not quantified.
VII. Request for Comments
The Administrator requests comments on all aspects of the proposed
revisions. All significant comments received will be considered in the
development and selection of the final revisions. The EPA specifically
solicits comment on whether, and on what basis, the output-based
standard being proposed for electric utility steam generating units
under subpart Da should be applied to industrial steam generating units
under subpart Db to promote energy efficiency. The EPA recognizes that
there are a multitude of applications for which industrial units
provide steam, such as basic plant heating and air conditioning,
drying, process heating, etc. In addition, industrial units often
supply steam for more than one application. As such, the net efficiency
of industrial steam generating units can cover a wide range depending
on what fraction of the energy delivered to the process actually is
used. Unlike utility applications, many industrial applications utilize
the heat of condensation. Thus, industrial units would have a much
higher net efficiency than a utility application (e.g., 38 percent).
Therefore, the output-based standard, as proposed for subpart Da, would
be inappropriate for industrial units.
Consequently, the EPA specifically requests comments and
information on: (1) how to encourage energy efficiency in industrial
applications; (2) whether an output-based format should be applied to
industrial steam generating units; (3) the range of net efficiencies
applicable to various industrial applications; (4) whether a generic or
separate output-based standards should be developed for different
industrial applications; (5) the appropriate baseline efficiency; and
(6) how the net efficiency of an industrial unit should be determined.
For example, the comments might outline the mechanisms or approaches
used by industrial facilities to determine the efficiency of various
process applications or what fraction of the energy delivered to the
process is actually used. Specific comments are requested from all
interested parties including State agencies, Federal agencies,
environmental groups, industry associations, and individual citizens.
Written comments must be addressed to the Air Docket Section address
given in the ADDRESSES section of this preamble, and must refer to
Docket No. A-92-71.
VIII. Administrative Requirements
A. Public Hearing
A public hearing will be held, if requested, to discuss the
proposed revisions in accordance with section 307(d)(5) of the Clean
Air Act. Persons wishing to make oral presentations on the proposed
revisions should contact EPA at the address given in the ADDRESSES
section of this preamble. Oral presentations will be limited to 15
minutes each. Any member of the public may file a written statement
before, during, or within 30 days after the hearing. Written statements
must be addressed to the Air Docket Section address given in the
ADDRESSES section of this preamble, and must refer to Docket No. A-92-
71.
A verbatim transcript of the hearing and written statements will be
available for public inspection and copying during normal working hours
at the EPA's Air Docket Section in Washington, D.C. (see ADDRESSES
section of this preamble).
B. Docket
The docket is an organized and complete file of all the information
submitted to, or otherwise considered by, EPA in the development of
this proposed rulemaking. The principal purposes of the docket are: (1)
to allow interested parties to readily identify and locate documents so
that they can intelligently and effectively participate in the
rulemaking process, and (2) to serve as the record in case of judicial
review (except for interagency review materials).
C. 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 any revisions to the standard resulting from this
proposal as required by the Act. 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 will welcome comments on all 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
proposing the revision to the standards. The economic impact assessment
is included in the docket listed at the beginning of today's notice
under SUPPLEMENTARY INFORMATION.
D. Office of Management and Budget Reviews
1. Paperwork Reduction Act
The proposed revisions contain no changes to the information
collection requirements of the current NSPS. Those requirements were
previously submitted for approval by the Office of Management and
Budget (OMB) during the original development of the NSPS.
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
[[Page 36960]]
economy of $100 million or more, or adversely and materially affecting
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, 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. 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.
3. Regulatory Flexibility Act
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 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. The Agency certifies
that the rule will not have a significant 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 proposed 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, 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 .07 percent. The range of average control cost
across industries varies from a low of .004 percent for primary metals
to a high of .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. Based on these estimates, EPA certifies that
the rule will not have a significant impact on a substantial number of
small entities.
4. Unfunded Mandates Act of 1995
Under section 202 of the Unfunded Mandates Reform Act of 1995
(``Unfunded Mandates Act''), signed into law on March 22, 1995, 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, 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 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 EPA's prior consultation with State, local, and
tribal officials.
Since this proposed rule is estimated to impose costs to the
private sector in excess of $100 million, EPA has prepared the
following statement with respect to these impacts.
a. Statutory authority.
The statutory authority for this rulemaking is identified and
described in Sections I and VII of the preamble. As required by section
205 of the Unfunded Mandates Act, and as described more fully in
Section III of this preamble, EPA has chosen to propose a rule that is
the least burdensome alternative for regulation of these sources that
meets the statutory requirements under the Act.
b. Costs and benefits.
As described in section VI of the 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
proposed 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 proposed rule. There are no federal funds
available to assist State, local, or tribal governments with these
indirect costs.
[[Page 36961]]
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 proposed regulation. A qualitative analysis of
industrial boiler replacement raises the possibility that replacement
delay due to the proposed 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 5 for a summary of linkages between NOX
emissions and damage categories.
Table 5.--Linkages Between NoX Emissions and Damage Categories: Strength of the Evidence
----------------------------------------------------------------------------------------------------------------
Direct Precursor effects
effects -----------------------------------------
-------------- Ambient
Ambient NOX Ambient particulate Acid
levels ozone levels matter deposition
----------------------------------------------------------------------------------------------------------------
Human Health:
Acute Morbidity.....................................
Chronic Morbidity................................... ............
Mortality........................................... ............ ............
Ecosystems:
Terrestrial.........................................
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.
c. 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
VII C. 4 of the preamble for more detail.
d. Effects on national economy.
Significant effects on the national economy from this proposed rule
are not anticipated. See section VIII C. 4 of the preamble for more
detail.
e. Consultation with government officials.
The Unfunded Mandates Act 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
EPA's response to those comments or concerns. In addition, section 203
of the Act requires that 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, 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, EPA is proposing a
higher NOX emission limit for industrial units than it is
proposing today 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 preamble, the impacts on small businesses and governments
have been analyzed and indicate that small governments are not
significantly
[[Page 36962]]
impacted by this rule and thus no plan is required.
F. Miscellaneous
List of Subjects in 40 CFR Part 60
Environmental protection, Air pollution control, Intergovernmental
relations, Incorporation by reference, Reporting and recordkeeping
requirements, Electric utility steam generating units, Industrial-
commercial-institutional steam generating units.
Statutory Authority
The statutory authority for this proposal 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.
Dated: July 1, 1997.
Carol M. Browner,
Administrator.
40 CFR part 60 is proposed to be 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 60.41a is amended by adding a definition for ``Net
output'' in alphabetical order to read as follows:
Sec. 60.41a Definitions.
* * * * *
Net output means the net useful work performed by the steam
generated taking into account the energy requirements for auxiliaries
and emission controls. For units generating only electricity, the net
useful work performed is the net electrical output (i.e., net busbar
power leaving the plant) from the turbine/generator set. For
cogeneration units, the net useful work performed is the net electrical
output plus one half the useful thermal output (i.e., steam delivered
to an industrial process).
* * * * *
3. Section 60.44a is amended by revising paragraphs (a)
introductory text, and (c) 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 in excess of the following emission limits,
based on a 30-day rolling average.
* * * * *
(c) Except as provided in paragraph (d) of this section, when two
or more fuels are combusted simultaneously, the applicable standard is
determined by proration using the following formula:
En = [86w+130x+210y+260z+340v]/100
Where:
En is the applicable standard for nitrogen oxides when
multiple fuels are combusted simultaneously (ng/J heat input);
w is the percentage of total heat input derived from the combustion of
fuels subject to the 86 ng/J heat input standard;
x is the percentage of total heat input derived from the combustion of
fuels subject to the 130 ng/J heat input standard;
y is the percentage of total heat input derived from the combustion of
fuels subject to the 210 ng/J heat input standard;
z is the percentage of total heat input derived from the combustion of
fuels subject to the 260 ng/J heat input standard;
v is the percentage of total heat input derived from the combustion of
fuels subject to the 340 ng/J heat input standard;
(d) 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 for which
construction, modification, or reconstruction commenced after July 9,
1997 any gases which contain nitrogen oxides in excess of 170 nanograms
per joule (1.35 pounds per megawatt-hour) net energy output.
4. Section 60.47a is amended by adding paragraph (k) to read as
follows:
Sec. 60.47a Emission monitoring.
* * * * *
(k) The procedures specified in paragraphs (k)(1) through (k)(3) of
this section shall be used to determine compliance with the output-
based standard under Sec. 60.44a(d).
(1) The owner or operator of an affected facility with electricity
generation shall install, calibrate, maintain, and operate a wattmeter;
measure net 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 net 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 net energy output is determined from
the net electrical output measured in paragraph (k)(1) of this section
plus 50 percent of the net thermal output of the process steam measured
in paragraph (k)(2) of this section.
5. Section 60.49a is amended by revising 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 to the Administrator for
every calendar quarter. All quarterly reports shall be postmarked by
the 30th day following the end of each 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 consistent with the electronic data
reporting format specified by the Administrator under Sec. 75.64 (d) of
this chapter. 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.
Subpart Db--[Amended]
6. 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,
[[Page 36963]]
or natural gas 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 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 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 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 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 from that affected
facility any gases that contain nitrogen oxides in excess of an
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 which 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/J
(0.20 lb/million Btu) heat input; 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.
7. Section 60.49b is amended by adding paragraph (u) to read as
follows:
Sec. 60.49b Reporting and recordkeeping requirements.
* * * * *
(u) 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 consistent with the
electronic data reporting format specified by the Administrator under
Sec. 75.64(d) of this chapter. 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.
[FR Doc. 97-17950 Filed 7-8-97; 8:45 am]
BILLING CODE 6560-50-P