[Federal Register Volume 70, Number 38 (Monday, February 28, 2005)]
[Proposed Rules]
[Pages 9706-9735]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 05-2996]
[[Page 9705]]
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Part II
Environmental Protection Agency
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40 CFR Part 60
Standards of Performance for Electric Utility Steam Generating Units
for Which Construction Is Commenced After September 18, 1978; Standards
of Performance for Industrial-Commercial-Institutional Steam Generating
Units; and Standards of Performance for Small Industrial-Commercial-
Institutional Steam Generating Units; Proposed Rule
Federal Register / Vol. 70, No. 38 / Monday, February 28, 2005 /
Proposed Rules
[[Page 9706]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[OAR-2005-0031; FRL-7873-8]
RIN 2060-AM80
Standards of Performance for Electric Utility Steam Generating
Units for Which Construction Is Commenced After September 18, 1978;
Standards of Performance for Industrial-Commercial-Institutional Steam
Generating Units; and Standards of Performance for Small Industrial-
Commercial-Institutional Steam Generating Units
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed amendments.
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SUMMARY: Pursuant to section 111(b)(1)(B) of the Clean Air Act (CAA),
the EPA has reviewed the emission standards for particulate matter
(PM), sulfur dioxide (SO2), and nitrogen oxides
(NOX) contained in the standards of performance for electric
utility steam generating units, industrial-commercial-institutional
steam generating units, and small industrial-commercial-institutional
steam generating units. This action presents the results of EPA's
review and proposes amendments to standards consistent with those
results. Specifically, we are proposing amendments to the PM,
SO2, and NOX emission standards. We are also
proposing to replace the current percent reduction requirement for
SO2 with an output-based SO2 emission limit. We
are also proposing an amendment to the PM emission limit. In addition
to amending the emissions limits, we also are proposing several
technical clarifications and corrections to existing provisions of the
current rules.
DATES: Comments on the proposed amendments must be received on or
before April 29, 2005.
Public Hearing: If anyone contacts EPA by March 21, 2005,
requesting to speak at a public hearing, EPA will hold a public hearing
on March 30, 2005. Persons interested in attending the public hearing
should contact Ms. Eloise Shepherd at (919) 541-5578 to verify that a
hearing will be held.
ADDRESSES: Submit your comments, identified by Docket ID
No. OAR-2005-0031, by one of the following methods: Federal
eRulemaking Portal: http://www.regulations.gov. Follow the on-line
instructions for submitting comments. Agency Web site: http://www.epa.gov/edocket. EDOCKET, EPA's electronic public docket and
comment system, is EPA's preferred method for receiving comments.
Follow the on-line instructions for submitting comments.
E-mail: Send your comments via electronic mail to [email protected], Attention Docket ID No. OAR-2005-0031.
By Facsimile: Fax your comments to (202) 566-1741, Attention Docket
ID No. OAR-2005-0031.
Mail: Send your comments to: EPA Docket Center (EPA/DC),
Environmental Protection Agency, Mailcode 6102T, 1200 Pennsylvania
Ave., NW., Washington, DC 20460, Attention Docket ID No. OAR-2005-0031.
Please include a total of two copies. The EPA requests a separate copy
also be sent to the contact person identified below (see FOR FURTHER
INFORMATION CONTACT). In addition, please mail a copy of your comments
on the information collection provisions to the Office of Information
and Regulatory Affairs, Office of Management and Budget (OMB), Attn:
Desk Officer for EPA, 725 17th St., NW., Washington, DC 20503.
Hand Delivery: Deliver your comments to: EPA Docket Center (EPA/
DC), EPA West Building, Room B108, 1301 Constitution Ave., NW.,
Washington, DC, Attention Docket ID No. OAR-2005-0031. Such deliveries
are accepted only during the normal hours of operation (8:30 a.m. to
4:30 p.m., Monday through Friday, excluding legal holidays), and
special arrangements should be made for deliveries of boxed
information.
Instructions: Direct your comments to Docket ID No. OAR-2005-0031.
The EPA's policy is that all comments received will be included in the
public docket without change and may be made available online at http://www.epa.gov/edocket, including any personal information provided,
unless the comment includes information claimed to be Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Do not submit information that you consider to
be CBI or otherwise protected through EDOCKET, regulations.gov, or e-
mail. The EPA EDOCKET and the Federal regulations.gov Web sites are
``anonymous access'' systems, which means EPA will not know your
identity or contact information unless you provide it in the body of
your comment. If you send an e-mail comment directly to EPA without
going through EDOCKET or regulations.gov, your e-mail address will be
automatically captured and included as part of the comment that is
placed in the public docket and made available on the Internet. If you
submit an electronic comment, EPA recommends that you include your name
and other contact information in the body of your comment and with any
disk or CD-ROM you submit. If EPA cannot read your comment due to
technical difficulties and cannot contact you for clarification, EPA
may not be able to consider your comment. Electronic files should avoid
the use of special characters, any form of encryption, and be free of
any defects or viruses.
Public Hearing: If a public hearing is held, it will be held at
EPA's Campus located at 109 T.W. Alexander Drive in Research Triangle
Park, NC, or an alternate site nearby.
Docket: All documents in the docket are listed in the EDOCKET index
at http://www.epa.gov/edocket. Although listed in the index, some
information is not publicly available, i.e., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy form. Publicly available docket
materials are available either electronically in EDOCKET or in hard
copy at the EPA Docket Center (EPA/DC), EPA West Building, Room B102,
1301 Constitution Ave., NW., Washington, DC. The Public Reading Room is
open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding
legal holidays. The telephone number for the Public Reading Room is
(202) 566-1744, and the telephone number for the EPA Docket Center is
(202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Mr. Christian Fellner, Combustion
Group, Emission Standards Division (C439-01), U.S. EPA, Research
Triangle Park, North Carolina 27711, (919) 541-4003, e-mail
[email protected].
SUPPLEMENTARY INFORMATION:
Organization of This Document. The following outline is provided to
aid in locating information in this preamble.
I. General Information
A. Does this action apply to me?
B. What should I consider as I prepare my comments for EPA?
II. Background Information
A. What is the statutory authority for the proposed amendments?
B. What is the role of the NSPS program?
III. Summary of the Proposed Amendments
A. What are the requirements for new electric utility steam
generating units (40 CFR part 60, subpart Da)?
B. What are the requirements for industrial-commercial-
institutional steam generating units (40 CFR part 60, subpart Db)?
C. What are the requirements for small industrial-commercial-
institutional
[[Page 9707]]
steam generating units (40 CFR part 60, subpart Dc)?
IV. Rationale for the Proposed Amendments
A. What is the performance of control technologies for steam
generating units?
B. Regulatory Approach
C. How did EPA determine the amended standards for electric
utility steam generating units (40 CFR part 60, subpart Da)?
D. How did EPA determine the amended standards for industrial-
commercial-institutional steam generating units (40 CFR part 60,
subparts Db and Dc)?
E. What technical corrections is EPA proposing?
V. Modification and Reconstruction Provisions
VI. Summary of Cost, Environmental, Energy, and Economic Impacts
A. What are the impacts for electric utility steam generating
units?
B. What are the impacts for industrial, commercial,
institutional boilers?
C. Economic Impacts
VII. Request for Comments
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination with
Indian Tribal Governments
G. Executive Order 13045: Protection of Children from
Environmental Health and Safety Risks
H. Executive Order 13211: Actions that Significantly Affect
Energy Supply, Distribution or Use
I. National Technology Transfer Advancement Act
I. General Information
A. Does This Action Apply to Me?
Regulated Entities. Categories and entities potentially regulated
by the proposed amendments are new electric utility steam generating
units and new, reconstructed, and modified industrial-commercial-
institutional steam generating units. The proposed amendments would
affect the following categories of sources:
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Examples of potentially regulated
Category NAICS code SIC code entities
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Industry................................. 221112 ................ Fossil fuel-fired electric
utility steam generating units.
Federal Government....................... 22112 ................ Fossil fuel-fired electric
utility steam generating units
owned by the Federal Government.
State/local/tribal government............ 22112 ................ Fossil fuel-fired electric
utility steam generating units
owned by municipalities.
921150 ................ Fossil fuel-fired electric steam
generating units in Indian
Country.
Any industrial-commercial-institutional 211 13 Extractors of crude petroleum and
facility using a boiler as defined in natural gas.
CFR 60.40b or CFR 60.40c.
321 24 Manufacturers of lumber and wood
products.
322 26 Pulp and paper mills.
325 28 Chemical manufacturers.
324 29 Petroleum refiners and
manufacturers of coal products.
316, 326, 339 30 Manufacturers of rubber and
miscellaneous plastic products.
331 33 Steel works, blast furnaces.
332 34 Electroplating, plating,
polishing, anodizing, and
coloring.
336 37 Manufacturers of motor vehicle
parts and accessories.
221 49 Electric, gas, and sanitary
services.
622 80 Health services.
611 82 Educational Services.
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This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be subjected to the
proposed amendments. To determine whether your facility may be subject
to the proposed amendments, you should examine the applicability
criteria in 40 CFR part 60, sections 60.40a, 60.40b, or 60.40c. If you
have any questions regarding the applicability of the proposed
amendments to a particular entity, contact the person listed in the
preceding FOR FURTHER INFORMATION CONTACT section.
B. What Should I Consider as I Prepare My Comments for EPA?
1. Submitting CBI. Do not submit information that you consider to
be confidential business information (CBI) electronically through
EDocket, regulations.gov, or e-mail. Send or deliver information
identified as CBI only to the following address: Mr. Christian Fellner,
c/o OAQPS Document Control Officer (Room C404-02), U.S. EPA, Research
Triangle Park, 27711, Attention Docket ID No. OAR-2005-0031. Clearly
mark the part or all of the information that you claim to be CBI. For
CBI information in a disk or CD ROM that you mail to EPA, mark the
outside of the disk or CD ROM as CBI and then identify electronically
within the disk or CD ROM the specific information that is claimed as
CBI. In addition to one complete version of the comment that includes
information claimed as CBI, a copy of the comment that does not contain
the information claimed as CBI must be submitted for inclusion in the
public docket. Information marked will not be disclosed except in
accordance with procedures set forth in 40 CFR part 2.
If you have any questions about CBI or the procedures for claiming
CBI, please consult the person identified in the FOR FURTHER
INFORMATION CONTACT section.
2. Tips for Preparing Your Comments. When submitting comments,
remember to:
a. Identify the proposed amendments by docket number and other
identifying information (subject heading, Federal Register date and
page number).
b. Follow directions. The EPA may ask you to respond to specific
questions or organize comments by referencing a Code of Federal
Regulations (CFR) part or section number.
c. Explain why you agree or disagree; suggest alternatives and
substitute language for your requested changes.
d. Describe any assumptions and provide any technical information
and/
[[Page 9708]]
or data that you used in formulating your comments.
e. If you estimate potential costs or burdens, explain how you
arrived at your estimate in sufficient detail to allow for it to be
reproduced.
f. Provide specific examples to illustrate your concerns, and
suggest alternatives.
g. Explain your views as clearly as possible, avoiding the use of
profanity or personal threats.
h. Make sure to submit your comments by the comment period deadline
identified.
Docket. The docket number for the proposed amendments to the
standards of performance (40 CFR part 60, subpart Da, Db, and Dc) is
Docket ID No. OAR-2005-0031. Other dockets incorporated by reference
for the standards of performance include Docket ID Nos. A-79-02, A-83-
27, A-86-02, and A-92-71.
Worldwide Web (WWW). In addition to being available in the docket,
an electronic copy of the proposed amendments is available on the WWW
through the Technology Transfer Network (TTN). Following signature, EPA
will post a copy of the proposed amendments on the TTN's policy and
guidance page for newly proposed or promulgated amendments at http://www.epa.gov/ttn/oarpg. The TTN provides information and technology
exchange in various areas of air pollution control. If more information
regarding the TTN is needed, call the TTN Help line at (919) 541-5384.
II. Background Information
A. What Is the Statutory Authority for the Proposed Amendments?
New source performance standards (NSPS) implement CAA section
111(b), and are issued for categories of sources which cause, or
contribute significantly to, air pollution which may reasonably be
anticipated to endanger public health or welfare.
Section 111 of the CAA requires that NSPS reflect the application
of the best system of emissions reductions which (taking into
consideration the cost of achieving such emissions reductions, any non-
air 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 current standards for steam generating units are contained in
the NSPS for electric utility steam generating units (40 CFR part 60,
subpart Da), industrial-commercial-institutional steam generating units
(40 CFR part 60, subpart Db), and small industrial-commercial-
institutional steam generating units (40 CFR part 60, subpart Dc).
The NSPS for electric utility steam generating units (40 CFR part
60, subpart Da) were originally promulgated on June 11, 1979 (44 FR
33580) and apply to units capable of firing more than 73 megawatts (MW)
(250 million British thermal units per hour(MMBtu/hr)) heat input of
fossil fuel that commenced construction, reconstruction, or
modification after September 18, 1978. The NSPS also apply to
industrial-commercial-institutional cogeneration units that sell more
than 25 MW and more than one-third of their potential output capacity
to any utility power distribution system. The most recent amendments to
emission standards under subpart Da, 40 CFR part 60, were promulgated
in 1998 (63 FR 49442) resulting in new NOX limitations for
subpart Da, 40 CFR part 60, units. Furthermore, in the 1998 amendments,
we incorporated the use of output-based emission limits.
The NSPS for industrial-commercial-institutional steam generating
units (40 CFR part 60, subpart Db) apply to units for which
construction, modification, or reconstruction commenced after June 19,
1984 that have a heat input capacity greater than 29 MW (100 MMBtu/hr).
Those standards were originally promulgated on November 25, 1986 (51 FR
42768) and also have been amended since the original promulgation to
reflect changes in BDT for these sources. The most recent amendments to
emission standards under subpart Db, 40 CFR part 60, were promulgated
in 1998 (63 FR 49442) resulting in new NOX limitations for
subpart Db, 40 CFR part 60, units.
The NSPS for small industrial-commercial-institutional steam
generating units (40 CFR part 60, subpart Dc) were originally
promulgated on September 12, 1990 (55 FR 37674) and apply to units with
a maximum heat input capacity greater than or equal to 2.9 MW (10
MMBtu/hr) but less than 29 MW (100 MMBtu/hr). Those standards apply to
units that commenced construction, reconstruction, or modification
after June 9, 1989.
Section 111(b)(1)(B) of the CAA requires the EPA periodically to
review and revise the standards of performance, as necessary, to
reflect improvements in methods for reducing emissions.
B. What Is the Role of the NSPS Program?
The NSPS program is one part of the CAA's integrated air quality
management program. The primary purpose of the NSPS are to achieve
long-term emissions reductions by ensuring that the best demonstrated
emission control technologies are installed as the industrial
infrastructure is modernized. Since 1970, the NSPS have been successful
in achieving long-term emissions reductions at numerous industries by
assuring cost-effective controls are installed on new, reconstructed,
or modified sources. Recently, however, with the rapid advance of
control technologies, the case-by-case new source review (NSR)
permitting program has required greater emissions reductions than
required by the NSPS, particularly for utility boilers. The existing
and proposed market-based cap and trade programs require greater
overall emissions reductions from the entire utility industry than the
technology-based emission limits of the NSPS can achieve by regulating
individual new sources.
Utility steam generators are subject to the current cap and trade
programs for acid rain, which imposes a national cap on annual utility
SO2 emissions, and for interstate transport of ozone, which
imposes a regional cap on summer time utility NOX emissions
in the eastern United States. The Administration's proposed Clear Skies
Act would impose three trading programs: a national SO2
trading program tighter than the acid rain trading program and two
annual NOX trading programs (one for the eastern United
States and one for the remaining part of the country). Alternatively,
EPA's Clean Air Interstate Rule (CAIR) proposes two new trading
programs for utility steam generators to further control SO2
and NOX emissions in the eastern United States to reduce the
transport of fine particulate matter and ozone.
Under these types of cap and trade programs, emissions of the
regulated pollutants from all the regulated units are capped at a
prescribed level (tons per year). Each affected unit is allocated a
number of emission allowances, each of which conveys the right to emit
a certain amount of the regulated pollutant. The total number of
allowances allocated for any given year equals the emissions cap for
that year. Each year, an affected unit must turn in a number of
allowances equal to its emissions. Allowances can be bought and sold.
Therefore, units can comply either by emitting equal to or less than
permitted by the number of allowances
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they have been allocated or by obtaining additional allowances. This
provides units with low cost reduction opportunities an incentive to
reduce emissions below their allocated levels and allows units that
face high costs for emissions reductions the opportunity to obtain
allowances.
It is useful to understand the relationship between the NSPS
program as it applies to utility steam generators and the various cap
and trade programs being implemented or under development. First, the
cap and trade program provides an incentive to apply modern emission
controls on new sources because installing controls on a new unit is
generally less expensive than installing similar controls on an
existing unit. Minimizing emissions from a new source minimizes the
allowances it must purchase (if no allowances are set aside for new
sources) or may even allow it to sell allowances (if allowances are
automatically allocated to new sources). Therefore, for source
categories and pollutants subject to a stringent industry-wide
emissions cap, a stringent NSPS is less important because new sources
already have an economic incentive to install state-of-the-art
controls. Second, over time, as technology improves, a cap continues to
provide an incentive to install better technology, especially on new
sources. In contrast, NSPS that are reviewed and amended every 8 years
are unlikely to keep pace with technological improvements. Since the
normal rulemaking process takes several years, more frequent updating
of NSPS are impractical.
Finally, for sources and pollutants subject to a tight industry-
wide emissions cap, stringent NSPS would have little or no effect on
overall emissions in the geographic area regulated by the cap. Even if
there were source specific reasons which result in it not making
economic sense to install as effective emission controls as would be
required under a stringent NSPS, that unit would have to use more
allowances. This would result in fewer allowances being available for
existing units, which would result in fewer emissions from existing
sources. Therefore, for the pollutants, geographic area, and sources
regulated by cap and trade programs, tighter NSPS would not necessarily
affect total emissions. However, the stringency of the NSPS could
affect the cost of achieving these emissions reductions. A cap and
trade program allows the market to determine the most cost-effective
way to achieve the overall emissions reductions goal. Installing modern
controls on new sources will be the most cost-effective choice for most
new sources. If there are circumstances where this is not the case,
then overly stringent NSPS could limit a new source from using the most
cost-effective controls for meeting its allocated portion of the
emissions cap, thereby raising the cost of controls without necessarily
increasing the environmental benefit.
The primary environmental benefit from the proposed amendments to
the utility NSPS would come from the reduction of direct PM emissions,
because direct emissions of PM are not subject to a cap and trade
program (nor has such a program been proposed). For SO2
(which is subject to a national trading program), the primary effect of
the proposed amendments would be to establish the minimum control
requirements for any steam generating units that are not subject to
NSR. For NOX, the same would be true nationally if Clear
Skies were to pass or would be true in the eastern United States if
CAIR is promulgated. Also, replacing the percent reduction requirement
for SO2 with an emission limit would harmonize the NSPS with
the cap and trade programs by providing sources more flexibility in
reducing emissions from new sources to meet the cap, while maintaining
the same aggregate emissions.
III. Summary of the Proposed Amendments
The proposed amendments would amend the emission limits for
SO2, NOX, and PM from steam generating units in
subpart Da, 40 CFR part 60, (Electric Utility Steam Generating Units),
and the PM emission limit for subpart Db, 40 CFR part 60, (Industrial-
Commercial-Institutional Steam Generating Units), and subpart Dc, 40
CFR part 60, (Small Industrial-Commercial-Institutional Steam
Generating Units). Only those units that begin construction,
modification, or reconstruction after February 28, 2005, would be
affected by the proposed amendments. Steam generating units subject to
the proposed amendments but for which construction, modification, or
reconstruction began on or before February 28, 2005, would continue to
comply with the applicable standards under the current NSPS. Compliance
with the proposed emission limits would be determined using the same
testing, monitoring, and other compliance provisions set forth in the
existing standards. In addition to amending the emission limits, we
also are proposing several technical clarifications and corrections to
existing provisions of the existing amendments, as explained below.
We are proposing language to clarify the applicability of subparts
Da, Db, and Dc of 40 CFR part 60 to combined cycle power plants. Heat
recovery steam generators that are associated with combined cycle gas
turbines burning natural gas or a fuel other than synthetic-coal gas
would not be subject to subparts Da, Db, or Dc, 40 CFR part 60, if the
unit meets the applicability requirements of subpart KKKK, 40 CFR part
60 (Standards of Performance for Stationary Combustion Turbines).
Subpart Da, Db, or Dc of 40 CFR part 60 would apply to a combined cycle
gas turbine that burns synthetic-coal gas (e.g., integrated coal
gasification combine cycle power plants) and meets the applicability
criteria of one of the proposed amendments, respectively.
We are proposing amendments to the definitions for boiler operating
day, coal, coal-derived fuels, oil, and natural gas. The purpose of the
proposed amendments is to clarify definitions across the three subparts
and to incorporate the most current applicable American Society for
Testing and Materials (ASTM) testing method references. Also, we are
proposing to clarify the definition of an ``electric utility steam
generating unit'' as applied to cogeneration units.
We are proposing several amendments to the provisions of the
existing rule related to the use of continuous emission monitoring
systems (CEMS) to obtain SO2 and NOX emission
data for determining compliance with the rule requirements. The
proposed amendments would eliminate duplicative or conflicting CEMS
requirements for utility steam generating units that are subject to
both 40 CFR part 60 and 40 CFR part 75 (acid rain).
A. What Are the Requirements for New Electric Utility Steam Generating
Units (40 CFR Part 60, Subpart Da)?
The proposed PM emission limit for electric utility steam
generating units is 6.4 nanograms per joule (ng/J) (0.015 lb/MMBtu)
heat input regardless of the type of fuel burned. Compliance with this
emission limit would be determined using the same testing, monitoring,
and other compliance provisions for PM standards set forth in the
existing rule.
The proposed SO2 emission limit for electric utility
steam generating units is 250 ng/J (2.0 pound per megawatt hour (lb/
MWh)) gross energy output regardless of the type of fuel burned with
one exception. The proposed SO2 emission limit for electric
utility steam
[[Page 9710]]
generating units that burn over 90 percent coal refuse is 300 ng/J (2.4
lb SO2/MWh) gross energy output. Under the existing subpart
Da of 40 CFR part 60, coal refuse is defined as waste products of coal
mining, physical coal cleaning, and coal preparation operations (e.g.,
culm, gob) containing coal, matrix material, clay, and other organic
and inorganic material. Compliance with the proposed SO2
emission limits would be determined on a 30-day rolling average basis
using a CEMS to measure SO2 emissions as discharged to the
atmosphere and following the compliance provisions in the existing rule
for the output-based NOX standards applicable to new sources
that were built after July 9, 1997.
The proposed NOX emission limit for electric utility
steam generating units is 130 ng/J (1.0 lb NOX/MWh) gross
energy output regardless of the type of fuel burned in the unit.
Compliance with this emission limit would be determined on a 30-day
rolling average basis using the testing, monitoring, and other
compliance provisions in the existing rule for the output-based
NOX standards applicable to new sources that were built
after July 9, 1997.
B. What Are the Requirements for Industrial-Commercial-Institutional
Steam Generating Units (40 CFR Part 60, Subpart Db)?
The proposed PM emission limit for industrial-commercial-
institutional steam generating units is 13 ng/J (0.03 lb/MMBtu heat
input) for units that burn coal, oil, wood, or a mixture of these fuels
with other fuels. This limit would apply to units larger than 29 MW
(100 million British thermal units per hour).
C. What Are the Requirements for Small Industrial-Commercial-
Institutional Steam Generating Units (40 CFR Part 60, Subpart Dc)?
The proposed PM emission limit for small industrial-commercial-
institutional steam generating units is 13 ng/J (0.03 lb/MMBtu heat
input) for units that burn coal, oil, wood, or a mixture of these fuels
with other fuels. This limit would apply to units between 8.7 MW and 29
MW (30 to 100 million Btu per hour).
IV. Rationale for the Proposed Amendments
A. What Is the Performance of Control Technologies for Steam Generating
Units?
Control technologies for steam generating units are based on either
pre-combustion controls, combustion controls, or post-combustion
controls. Pre-combustion controls remove contaminants from the fuel
before it is burned, and combustion controls reduce the amount of
pollutants formed during combustion. Post-combustion controls remove
pollutants formed from the flue gases before the gases are released to
the atmosphere.
Selecting control technologies to reduce emissions of PM,
SO2, and NOX from a new steam generating unit is
a function of the type of fuel burned in the unit, the size of the
unit, and other site-specific factors (e.g., type of unit, firing and
loading practices used, regional and local air quality requirements).
All new steam generating units incorporate control technologies to
reduce NOX emissions. Natural gas is a gaseous fuel composed
of methane and other hydrocarbons with trace amounts of sulfur and no
ash. Accordingly, PM and SO2 emissions from steam generating
units firing natural gas are inherently low and generally do not
require the use of additional PM or SO2 control
technologies. For new steam generating units firing fuel oils, PM and
SO2 controls may be required depending on the grade and
composition of the fuel oil being burned in the unit. New steam
generating units firing coal use PM and SO2 controls.
1. PM Control Technologies
Filterable PM emissions from a steam generating unit are
predominately fly ash and carbon. Carbon particles are generated from
incomplete combustion of the fuel, and fly ash from burning fuels
containing ash materials (the mineral and other incombustible matter
portion of a fuel). These incombustible solid materials are released
during the combustion process and are entrained in the flue gases.
Distillate oils contain insignificant levels of ash, but residual fuel
oils have higher ash contents, up to 0.5 percent. While different ranks
of coals vary in ash content, all coals contain significant quantities
of ash. The percentage of ash in a given coal can vary from less than 5
percent to greater than 20 percent depending on the coal source and
level of coal cleaning.
Control of PM emissions from steam generating units relies on the
use of post-combustion controls to remove solid particles from the flue
gases. Electrostatic precipitators (ESP) and fabric filters (also
called baghouses) are the predominant technologies used to control PM
from coal-fired steam generating units. Either of these PM control
technologies can be designed to achieve overall PM collection
efficiencies in excess of 99.9 percent. Control of PM emissions from
oil-fired steam generating units can be achieved by using oil burner
designs with improved atomization and fuel mixing characteristics, by
implementing better maintenance practices, and by using an ESP.
Electrostatic Precipitator. An ESP operates by imparting an
electrical charge to incoming particles, and then attracting the
particles to oppositely charged metal plates for collection.
Periodically, the particles collected on the plates are dislodged in
sheets or agglomerates (by rapping the plates) and fall into a
collection hopper. The fly ash collected in the ESP hopper is a solid
waste that is either recycled for industrial use or disposed of in a
landfill.
The effectiveness of particle capture in an ESP depends primarily
on the electrical resistivity of the particles being collected. The
size requirement for an ESP increases with increasing coal ash
resistivity. Resistivity of coal fly ash can be lowered by conditioning
the particles upstream of the ESP with sulfur trioxide, sulfuric acid,
water, or sodium. In addition, collection efficiency is not uniform for
all particle sizes. Collection efficiencies greater than 99.9 percent,
however, are achievable for small particles (less than 0.1 micrometer
([mu]m)) and large particles (greater than 10 [mu]m). Collection
efficiencies achieved by ESP for the portion of particles having sizes
between 0.1 [mu]m and 10 [mu]m tend to be lower.
Fabric Filters. A fabric filter collects PM in the flue gases by
passing the gases through a porous fabric material. The buildup of
solid particles on the fabric surface forms a thin, porous layer of
solids, which further acts as a filtration medium. Gases pass through
this cake/fabric filter, and all but the finest-sized particles are
trapped on the cake surface. Collection efficiencies of fabric filters
can be as high as 99.99 percent.
A fabric filter must be designed and operated carefully to ensure
that the bags inside the collector are not damaged or destroyed by
adverse operating conditions. The fabric material must be compatible
with the gas stream temperatures and chemical composition. Because of
the temperature limitations of the available bag fabrics, location of a
fabric filter for use by a coal-fired electric steam generating unit is
restricted to locations downstream of the air heater.
[[Page 9711]]
2. SO2 Control Technologies
During combustion, sulfur compounds present in a fuel are
predominately oxidized to gaseous SO2. A small portion of
the SO2 oxidizes further to sulfur trioxide
(SO3). One approach to controlling SO2 emissions
from steam generating units is to limit the maximum sulfur content in
the fuel. This can be accomplished by burning a fuel that naturally
contains low amounts of sulfur or a fuel that has been pre-treated to
remove sulfur from the fuel. A second approach is use a post-combustion
control technology that removes SO2 from the flue gases.
These technologies rely on either absorption or adsorption processes
that react SO2 with lime, limestone, or another alkaline
material to form an aqueous or solid sulfur by-product.
Coal Pre-Treatment. Sulfur in coal occurs as either inorganic
sulfur or organic sulfur that is chemically bonded with carbon. Pyrite
is the most common form of inorganic sulfur. There are two ways to pre-
treat coal before combustion to lower sulfur emissions: Physical coal
cleaning and gasification. Physical cleaning removes between 20 to 90
percent of pyritic sulfur, but is not effective at removing organic
sulfur. The amount of pyritic sulfur varies with different coal types,
but it is typically half of the total sulfur for high sulfur coals.
Coal gasification breaks coal apart into its chemical constituents
(typically a mixture of carbon monoxide, hydrogen, and other gaseous
compounds) prior to combustion. The product gas is then cleaned of
contaminants prior to combustion. Gasification reduces SO2
emissions by over 99 percent.
Alkali Wet Scrubbing. The SO2 in a flue gas can be
removed by reacting the sulfur compounds with a solution of water and
an alkaline chemical to form insoluble salts that are removed in the
scrubber effluent. The most commonly used wet flue gas desulfurization
(FGD) systems for coal-fired steam generating units are based on using
either limestone or lime as the alkaline source. In a wet scrubber, the
flue gas enters a large vessel located downstream of the particle
control device where it contacts the lime or limestone slurry. The
calcium in the slurry reacts with the SO2 to form reaction
products that are predominately calcium sulfite. Because of its high
alkalinity, fly ash is sometimes mixed with the limestone or lime.
Other alkaline solutions can be used for scrubbing including sodium
carbonate, magnesium oxide, and dual alkali.
The SO2 removal efficiency that a wet FGD system can
achieve for a specific steam generating unit is affected by the sulfur
content of the fuel burned, which determines the amount of
SO2 entering the wet scrubber, and site-specific scrubber
design parameters including liquid-to-gas ratio, pH of the scrubbing
medium, and the ratio of the alkaline sorbent to SO2. Annual
SO2 removal efficiencies have been demonstrated above 98
percent. Advanced wet scrubber designs include limestone scrubbing with
forced oxidation (LSFO) and magnesium enhanced lime scrubbing FGD
systems.
Limestone Scrubbing with Forced Oxidation. Limestone scrubbing with
forced oxidation is a variation of the wet scrubber described above and
can use either limestone or magnesium enhanced lime. In the LSFO
process, the calcium sulfite initially formed in the spray tower
absorber is oxidized to form gypsum (calcium sulfate) by bubbling
compressed air through the sulfite slurry. The resulting gypsum by-
product has commercial value and can be sold to wallboard
manufacturers. Also, because of their larger size and structure, gypsum
crystals settle and dewater better than calcium sulfite crystals,
reducing the required size of by-product handling equipment. The high
gypsum content also permits disposal of the dewatered waste without
fixation.
Spray Dryer Adsorption. An alternative to using wet scrubbers is to
use spray dryer adsorber technology. A spray dryer adsorber operates by
the same principle as wet lime scrubbing, except that instead of a bulk
liquid (as in wet scrubbing) the flue gas containing SO2 is
contacted with fine spray droplets of hydrated lime slurry in a spray
dryer vessel. This vessel is located downstream of the air heater
outlet where the gas temperatures are in the range of 120 [deg]C to 180
[deg]C (250 [deg]F to 350 [deg]F). The SO2 is absorbed in
the slurry and reacts with the hydrated lime reagent to form solid
calcium sulfite and calcium sulfate. The water is evaporated by the hot
flue gases and forms dry, solid particles containing the reacted
sulfur. Most of the SO2 removal occurs in the spray dryer
vessel itself, although some additional SO2 capture has also
been observed in downstream particulate collection devices. This
process produces a dry waste product, which is mostly disposed of in a
landfill.
The primary operating parameters affecting SO2 removal
are the calcium-reagent-to-sulfur stoichiometric ratio and the approach
to saturation in the spray dryer. To decrease sorbent costs, a portion
of the solids collected in the spray dryer and the PM collection device
may be recycled to the spray dryer. The SO2 removal
efficiencies of new lime spray dryer systems are generally greater than
90 percent.
Dry Injection. For the dry injection process, dry hydrated or
slaked lime (or another suitable sorbent) is directly injected into the
ductwork or boiler upstream of a PM control device. Some systems use
spray humidification followed by dry injection. The SO2 is
adsorbed and reacts with the powdered sorbent. The dry solids are
entrained in the combustion gas stream, along with fly ash, and then
collected by the downstream PM control device.
The dry injection process produces a dry, solid by-product that is
easier to dispose. However, the SO2 removal efficiencies for
existing dry injection systems are lower than for the other FGD
technologies ranging from approximately 40 to 60 percent when using
lime or limestone, and up to 90 percent using other sorbants (e.g.,
sodium bicarbonate).
Fluidized-bed Combustion with Limestone. One of the appealing
features of selecting a steam generating unit that uses a fluidized-bed
combustor (FBC) is the capability to control SO2 emissions
during the combustion process. This is accomplished by adding finely
crushed limestone along with the coal (or other solid fuel) to the
fluidized bed. During combustion, calcination of the limestone
(reduction to lime by subjecting to heat) occurs simultaneously with
the oxidation of sulfur in the coal to form SO2. The
SO2, in the presence of excess oxygen, reacts with the lime
particles to form calcium sulfate. The sulfated lime particles are
removed with the bottom ash or collected with the fly ash by a
downstream PM control device (for most existing FBC steam generating
unit applications, a fabric filter is used as the PM control device).
Fresh limestone is continuously fed to the bed to replace the reacted
limestone. The SO2 removal efficiencies for some FBC units
are in the range of approximately 80 to 98 percent.
3. NOX Control Technologies
Nitrogen oxides are formed in a steam generating unit by the
oxidation of molecular nitrogen in the combustion air and any nitrogen
compounds contained in the fuel. The formation of NOX from
nitrogen in the combustion air is dependent on two conditions occurring
simultaneously in the unit's combustion zone: high temperature and an
excess of combustion air. Under these conditions, significant
quantities
[[Page 9712]]
of NOX are formed regardless of the fuel type burned. New
steam generating units being installed today in the United States
routinely include burners and other features designed to reduce the
amounts of NOX formed during combustion.
Beyond the lower levels of NOX emissions achieved using
combustion controls, additional NOX emission control can be
achieved for steam generating units by installing post-combustion
control technologies. These technologies involve converting the
NOX in the flue gas to molecular nitrogen (N2) and water
using either a process that requires a catalyst (called selective
catalytic reduction (SCR)) or a process that does not use a catalyst
(called selective noncatalytic reduction (SNCR)). Both SCR and SNCR
technologies have been applied widely to gas-, oil-, and coal-fired
steam generating units.
NOX Combustion Controls. Combustion controls reduce NOX
emission formation by controlling the peak flame temperature and excess
air in and around the combustion zone through staged combustion. With
staged combustion, the primary combustion zone is fired with most of
the air needed for complete combustion of the fuel. The remaining air
is introduced into the products of the partial combustion in a second
combustion zone. Air staging lowers the peak flame temperature, thereby
reducing thermal NOX, and reduces the production of fuel
NOX by reducing the oxygen available for combination with
the fuel nitrogen. Staged combustion may be achieved internally in the
fuel burners using specially designed burner configurations (often
referred to as low-NOX burners), or external to the burners
by diverting a portion of the combustion air from the burners and
introducing it through separate ports and/or nozzles, mounted above the
burners (often referred to as overfire air (OFA)). The actual
NOX reduction achieved with a given NOX
combustion control technology varies from unit to unit. Use of low-
NOX burners can reduce NOX emissions by
approximately 35 to 55 percent. Use of OFA reduces NOX
emissions levels in the range of 15 to 30 percent. Higher
NOX emissions reductions are achieved when combustion
control technologies are combined (e.g., combining OFA with low-
NOX burners can achieve NOX emissions reductions
in the range of 60 percent).
Other NOX combustion control techniques include
reburning, co-firing natural gas, and flue gas recirculating. In
reburning, coal, oil, or natural gas is injected above the primary
combustion zone to create a fuel rich zone to reduce burner-generated
NOX to N2 and water vapor. Overfire air is added above the
reburning zone to complete combustion of the reburning fuel. Natural
gas co-firing consists of injecting and combusting natural gas near or
concurrently with the main oil or coal fuel. Flue gas recirculating
decreases combustion temperatures by mixing flue gases with the
incoming combustion air. For gas and oil units, flue gas recirculating
can reduce NOX emissions by 75 percent.
SCR Technology. The SCR process uses a catalyst with ammonia
(NH3) to reduce the nitrogen oxide (NO) and nitrogen dioxide
(NO2) in the flue gas to molecular nitrogen and water.
Ammonia is diluted with air or steam, and this mixture is injected into
the flue gas upstream of a metal catalyst bed that typically is
composed of vanadium, titanium, platinum, or zeolite. The SCR catalyst
bed reactor is usually located between the economizer outlet and air
heater inlet, where temperatures range from 230 [deg]C to 400 [deg]C
(450 [deg]F to 750 [deg]F). The SCR technology is capable of
NOX reduction efficiencies of 90 percent or higher.
SNCR Technology. A SNCR process is based on the same basic
chemistry of reducing the NO and NO2 in the flue gas to molecular
nitrogen and water, but does not require the use of a catalyst to
promote these reactions. Instead, the reducing agent is injected into
the flue gas stream at a point where the flue gas temperature is within
a specific temperature range of 870 [deg]C to 1,090 [deg]C (1,600
[deg]F to 2,000 [deg]F). Currently, two SNCR processes are commercially
available; one uses ammonia as the reagent, and the other process uses
an aqueous urea solution in place of ammonia. The NOX
reduction levels for SNCR are in the range of approximately 30 to 50
percent.
B. Regulatory Approach
We have reviewed emission data and control technology information
applicable to criteria pollutants and have concluded that the
regulation of NOX, PM, and SO2 emissions from
these sources under the NSPS is appropriate. The proposed amendments to
the NSPS reflect the BDT for these sources based on the performance and
cost of the emission control technologies discussed above. In amending
the emission limits based on BDT, we have incorporated a fuel-neutral
concept and, to the extent that it is practical and reasonable, output-
based emission limits. These approaches provide the level of emission
limitation required by the CAA for the NSPS program and achieve
additional benefits of compliance flexibility, increased efficiency,
and the use of cleaner fuels.
1. Fuel-Neutral Approach
We are proposing to amend emission limits using a fuel-neutral
approach in most cases. This approach is currently used for the
NOX emission standards under subparts Da and Db of 40 CFR
part 60 and encourages pollution prevention by recognizing the
environmental benefits of combustion controls based on the use of clean
fuels. The fuel-neutral approach provides a single emission limit for
steam generating units based on BDT without regard to specific type of
steam generating equipment or fuel type. This approach provides an
incentive to facilities to consider fuel use, boiler type, and control
technology when developing an emission control strategy. Therefore,
owners and operators of affected sources are able to use the most
effective combination of add-on control technologies, clean fuels, and
boiler design to meet the emission limit. For example, an owner and
operator may decide that the blending of a low sulfur fuel with coal or
physically washing the coal in combination with dry-injection
technology would be a more cost-effective way of meeting the NSPS than
burning a higher sulfur coal and installing a FGD system.
Alternatively, if a source does not have long-term access to clean
fuels at a reasonable cost, then emission control technology is
available to allow units to burn higher sulfur fuels and still comply
with the emission limits.
To develop a fuel-neutral emission limit, we analyzed emission
control performance from coal-fired units to establish an emission
level that represents BDT. The higher sulfur, nitrogen, and ash
contents for coal compared to oil or gas makes application of BDT to
coal-fired units more complex than application to either oil-or gas-
fired units. Therefore, emission levels selected for coal-fired steam
generating units using BDT would be achievable by oil- and gas-fired
electric utility steam generating units. The resulting emission levels
from coal-fired units would apply to all boiler types and fuel use
combinations. It is appropriate for all fuels to have the same limits
to avoid discouraging the use of cleaner fuels. The BDT analysis was
conducted separately for 40 CFR part 60, subparts Da, Db, and Dc.
2. Output-Based Emission Standards
We have established pollution prevention as one of our highest
[[Page 9713]]
priorities. One of the opportunities for pollution prevention is
maximizing the efficiency of energy generation. An output-based
standard establishes emission limits in a format that incorporates the
effects of unit efficiency by relating emissions to the amount of
useful-energy generated, not the amount of fuel burned. By relating
emission limitations to the productive output of the process, output-
based emission limits encourage energy efficiency because any increase
in overall energy efficiency results in a lower emission rate. Allowing
energy efficiency as a pollution control measure provides regulated
sources with an additional compliance option that can lead to reduced
compliance costs as well as lower emissions. The use of more efficient
technologies reduces fossil fuel use and leads to multi-media
reductions in environmental impacts both on-site and off-site. On-site
benefits include lower emissions of all products of combustion,
including hazardous air pollutants, as well as reducing any solid waste
and wastewater discharges. Off-site benefits include the reduction of
emissions and non-air environmental impacts from the production,
processing, and transportation of fuels.
While output-based emission limits have been used for regulating
many industries, input-based emission limits have been the traditional
method to regulate steam generating units. However, this trend is
changing as we seek to promote pollution prevention and provide more
compliance flexibility to combustion sources. For example, in 1998 we
amended the NSPS for electric utility steam generating units (40 CFR
part 60, subpart Da) to use output-based standards for NOX
(40 CFR 63.44a, 62 FR 36954, and 63 FR 49446). In this action, we are
proposing output-based emission limits for SO2 and
NOX under subpart Da of 40 CFR part 60. The format of the
proposed output-based limits is mass of pollutant per megawatt hour of
gross energy output. We are proposing to base the limits on gross
energy output because of the monitoring difficulties in measuring net
output. The current output-based emission limit for NOX in
subpart Da of 40 CFR part 60 is based on gross energy output. The
difficulties of monitoring net energy output are explained in the
preamble to the 1998 NOX amendment for subpart Da of 40 CFR
part 60 (63 FR 49448).
Electrical Generating Units. For subpart Da of 40 CFR part 60, we
are proposing amendments which establish output-based emission limits
for SO2 and NOX. For PM, we are proposing an
amended input-based emission limit and requesting comments on an
output-based limit. The proposed output-based emission limit for
SO2 will replace both the current percentage reduction
requirement and input-based emission limit.
Industrial-Commercial-Institutional Units. For subpart Db of 40 CFR
part 60, we are soliciting comment on an optional output-based
NOX emission limit for units that generate electricity.
Units that generate electricity have the greatest opportunity for
achieving increases in energy efficiency. We would structure the
output-based limit as an option because we determined that for some
applications of industrial, commercial, and institutional boilers, the
monitoring, recordkeeping, and reporting costs for demonstrating
compliance with output-based emission limits would be unreasonable.
Determining compliance with an output-based emission limit requires
the use of a CEMS. Specifically, emission data must be collected in
units of pounds per hour to calculate an output-based emission rate.
The CEMS currently required by subpart Db of 40 CFR part 60, do not
provide that data. A CEMS also would need to collect continuous exhaust
flow data to calculate emissions in units of pounds per hour.
Additionally, continuous energy monitoring devices would be needed to
comply with an output-based limit. Not all electric generating units
subject to subpart Db of 40 CFR part 60 may be designed with these
monitoring systems. Due to costs, we are not expanding the monitoring
requirements under subpart Db of 40 CFR part 60 to require the
collection of exhaust flow and electrical generation data, and we are
not proposing an output-based emission limit for subpart Db of 40 CFR
part 60. Instead, we are proposing that individual facilities be given
the option of complying with either the current input-based or an
equivalent output-based limit.
Output-based limits may be feasible for NOX at units
that operate continuous emission flow and electrical generation
monitoring equipment. For example, some industrial-commercial-
institutional electric generating units may be required to install
continuous exhaust flow monitoring systems to demonstrate compliance
with State regulatory programs, such as NOX requirements in
State implementation plans. Where the required monitors are in place,
an output-based emission limit provides an incentive for increased
energy efficiency and the use of highly efficient technologies like
combined heat and power systems (next section).
The use of output-based emission limits is less feasible for PM
because current regulations generally do not require industrial-
commercial-institutional steam generators to operate PM CEMS.
Furthermore, the percent removal format for SO2 contained in
subpart Db of 40 CFR part 60 is not compatible with an output-based
standard.
3. Combined Heat and Power
Combined heat and power (CHP) is the sequential generation of power
(electricity or shaft power) and thermal energy from a common
combustion source. The application of CHP captures and uses much of the
waste heat that ordinarily is discarded from conventional electrical
generation, where two-thirds of the input energy typically becomes
waste heat (through exhaust stacks and cooling towers). In a CHP
system, this captured energy can be used to provide process heat and
space cooling or heating. By recovering waste heat, CHP systems achieve
much higher fuel efficiencies than separate electric and thermal
generators, and emit less pollution. Using CHP is a method for industry
not only to decrease criteria pollutants and hazardous air pollutants,
but also to move forward on addressing concerns about increasing levels
of heat trapping gases in the atmosphere.
Because CHP units produce both electrical and thermal energy, the
proposed amendments must account for both types of energy in
demonstrating compliance with an output-based emission limit. Energy
output for CHP units is the sum of gross electrical output and the
useful energy of the process steam. For the output-based emission
limits currently contained in subpart Da of 40 CFR part 60, we defined
the useful energy of the process steam from CHP units as 50 percent of
the thermal output. We chose the 50 percent allowance at that time
because using an allowance as if the steam would be converted to
electricity (up to 38 percent efficiency) would not account for the
environmental benefits of CHP applications, and allowing 100 percent
could potentially overstate the environmental benefits of CHP
applications. Additionally, this approach to CHP units was consistent
with a Federal Energy Regulatory Commission (FERC) regulation
determining the efficiency of CHP units.
In the proposed amendments, we are soliciting comments on the
appropriateness of giving more than 50 percent credit for thermal
output, and on a different approach to account for the thermal energy
from CHP units. The proposed approach would account for
[[Page 9714]]
the efficiency benefits of the thermal output based on the amount of
avoided emissions that a conventional boiler system would otherwise
emit had it provided the same thermal output as the CHP system. The
avoided emissions would be determined for each unit based on individual
unit operating factors. The proposed compliance procedures for CHP
units follow this logic:
(1) Determine the emission rate of the combustion source that
provides energy to the CHP unit (in units of pounds per hour) from the
continuous emission and flow monitoring system;
(2) Calculate the avoided emissions (in units of pounds per hour)
for the amount of thermal energy generated from the CHP unit; and
(3) Subtract the avoided emissions from the total emissions of the
CHP unit and divide that value by the gross electrical output of the
CHP unit.
This approach more accurately reflects the environmental benefits
of CHP units and accounts for site-specific differences in system
design, operation, and various power-to-heat ratios (the ratio of gross
electrical energy generation to useful thermal energy generation).
If a CHP unit demonstrates compliance with the output-based
emission limit, an output-based emission rate would be calculated based
on the following equation:
Echp = [Et - THa]/Oe (Eq. 1)
Where:
Echp = CHP emission rate (lb/MWh)
Et = total emissions (pounds per hour (lb/hr))
THa = avoided thermal emissions (lb/hr)
Oe = electrical output (MW)
The avoided thermal emissions (A) would be calculated based on the
following equation:
A = [E/0.8] * Oth (Eq. 2)
Where:
A = avoided thermal emissions (lb/hr)
E = applicable NSPS emission limit for the displaced boiler (pound per
million British thermal units heat input (lb/MMBtu))
0.8 = assumed boiler efficiency (percent)
Oth = thermal output (MMBtu/hr)
Under this approach, the avoided emission rate for the displaced
steam generating capacity would be calculated using the input-based 40
CFR part 60, subpart Db, NSPS emission limit applicable to the steam
generating unit. This is appropriate since, in the absence of the CHP
facility, the thermal energy would be provided by a new boiler subject
to 40 CFR part 60, subpart Db. The NSPS limit would be converted from
an input- to a thermal output-based emission rate by dividing the
input-based emission limit by an assumed thermal system efficiency of
80 percent. We have chosen a boiler thermal efficiency of 80 percent
because it is considered reasonable and takes into consideration all
fuels and a variety of design configurations used for boilers in CHP
facilities. Then, the avoided emission rate is converted to units of
pounds per hour by multiplying by the recovered useful thermal output
of the CHP system. We are soliciting comments both on this approach and
other methods of determining displaced thermal emissions besides a
boiler subject to 40 CFR part 60, subpart Db.
C. How Did EPA Determine the Amended Standards for Electric Utility
Steam Generating Units (40 CFR Part 60, Subpart Da)?
New source performance standards for electric utility steam
generating units in the proposed amendments would apply only to
affected sources that begin construction, modification, or
reconstruction after February 28, 2005. As discussed earlier in this
preamble, the regulatory approach we are using to develop the proposed
standards is based on our determination of BDT for control of PM,
SO2, and NOX from electric utility steam
generating units. Furthermore, we decided that the proposed standards
should use a fuel-neutral and an output-based emission limit format, to
the extent that it is practical and reasonable.
To set the proposed output-based standards at new plants, we used
measured output-based emissions where available. When gross output
information was unavailable, we selected emission limits based on heat
input and used a gross electrical efficiency to determine the output-
based standard. Recent technical publications assert that new
supercritical plants will be able to achieve net efficiencies as high
as 45 percent, and analysis of EPA's Clean Air Markets Division data
indicates that the top 10 percent of utility units are presently
operating at a gross efficiency of 38 percent or greater. However, to
account for variations in boiler designs and to allow efficiency as a
control technology, we selected 36 percent gross efficiency (top 25
percent of existing units) as our conversion factor. We are soliciting
comments on this approach and the appropriateness of the selected
value.
Only three new coal utility units have been built since the prior
NSPS amendments in 1998. The plants are the Red Hills facility in
Mississippi, the Hawthorn facility in Missouri, and the Northside
facility in Florida. These plants are designed to burn lignite,
subbituminous, and bituminous coal, respectively. To provide a broader
set of data to base the proposed amendments on, we also analyzed older
plants that have been retrofitted with controls.
1. Selection of the Proposed PM Standard
Direct particulate matter emissions from steam generating units
firing coal result from the entrainment of fly ash in the flue gases
and, to a lesser extent, from unburned fuel particles and downstream
post-combustion reactions. Currently, 40 CFR part 60, subpart Da,
limits PM emissions from electric utility steam generating units to
0.03 lb/MMBtu heat input regardless of the fuel burned in the unit.
Coal-fired electric utility steam generating units meeting the
current PM emission limit under subpart Da, 40 CFR part 60,
predominately use either a fabric filter or ESP to remove PM from the
flue gases. Over the years, the performance of fabric filters and ESP
installed on coal-fired steam generating units has improved as a result
of advanced control device designs and other performance enhancements
(e.g., use of new bag materials for fabric filters and use of computer
modeling and improved rapper and electrical system designs for ESP). We
concluded that fabric filters and ESP represent BDT for continuous
reduction of PM emissions from coal-fired electric utility steam
generating units.
To assess performance levels achievable by fabric filters and ESP
installed on new coal-fired electric utility steam generating units, we
reviewed the permits of three recent facilities covered under subparts
Da of 40 CFR part 60. The permit limits for the Hawthorn, Red Hills,
and Northside facilities are 0.018, 0.015, and 0.011 lb PM/MMBtu heat
input respectively. The Hawthorn limit includes condensible PM, and the
facility is achieving filterable PM control of 0.012 lb/MMBtu. The
Northside facility is achieving filterable PM control of 0.004 lb/
MMBtu. Based on this information, we concluded that current fabric
filter and ESP control technologies being installed on new electric
utility steam generating units can achieve PM emission levels below the
level of the existing PM standard, and that amending this PM standard
for new electric utility steam generating units is warranted.
To select a level for the proposed PM standard, we evaluated the
cost-effectiveness of two limits (0.018 lb PM/MMBtu and 0.015 lb PM/
MMBtu) along
[[Page 9715]]
with the ability of a broad range of coal types and boiler
configurations to achieve the standard. The annual reduction and
incremental cost of reducing PM emissions from the existing NSPS (0.03
lb/MMBtu) to 0.018 lb/MMBtu is 420 tons at an average incremental cost
of $3,100/ton. The annual reduction and incremental cost of reducing
the PM standard from 0.018 lb/MMBtu to 0.015 lb/MMBtu is 110 tons at an
average incremental cost of $8,400/ton. We selected a level for the
proposed standard considering the above performance information, non-
air quality health effects, and effects on energy production associated
with achieving these emission levels. The proposed PM standard is 6.5
ng/J (0.015 lb/MMBtu heat input). Based on information from the
Department of Energy Cost and Quality of Fuels for Electric Utility
Plants 2001, 75 percent of existing coal utility units would be able to
comply with the proposed limit using either an ESP or fabric filter
operating at a 99.8 percent collection efficiency, and 95 percent would
be able to comply with either an ESP or fabric filter operating at a
99.9 percent collection efficiency. The remaining 5 percent would be
able to comply with either a high efficiency ESP or fabric filter
operating at a 99.95 percent collection efficiency or coal washing in
conjunction with a less efficient PM control device. We are
particularly interested in soliciting comments providing information to
guide this determination. In the event data is presented indicating a
more stringent standard is achievable, we would consider a 4.7 ng/J
(0.011 lb/MMBtu heat input) standard. If data is presented
demonstrating that this standard will pose significant technical
difficulties for a range of fuels, we would consider a standard of 8.6
ng/J (0.02 lb/MMBtu heat input).
2. How Did EPA Select the Proposed SO2 Standard?
The current SO2 standard in 40 CFR part 60, subpart Da,
uses a percent reduction format in conjunction with a maximum emission
limit but provides an allowance for a lower percent reduction
requirement if a target emission limit is demonstrated. Effectively,
these standards require a new coal-fired steam generating unit to
achieve a 90 percent reduction of the potential combustion
concentration of SO2 (i.e., the theoretical amount of
SO2 that would be emitted in the absence of using any
emission control systems), and meet an emission limit of 1.2 lb
SO2/MMBtu heat input. However, if a unit can demonstrate an
SO2 emission rate less than 0.6 lb/MMBtu heat input, then
the unit is only required to achieve a 70 percent reduction.
As discussed earlier in this preamble, a number of SO2
control technologies are currently available for use with new coal-
fired electric utility steam generating units. The SO2
control strategy used for a particular new electric utility steam
generating unit project is fundamentally determined by the type of
combustion technology that is selected for the new unit. Owners and
operators building a new steam generating unit using integrated
gasification combined cycle (IGCC) or fluidized-bed combustion
technology generally use different control strategies than owners and
operators building a new steam generating unit using pulverized coal
combustion technology.
Another important factor influencing the selection of
SO2 control technology for a new unit is the sulfur content
of the coals expected to be burned. According to the most recent
Department of Energy data (FERC form-423 and form EIA-423), non-refuse
coal-fired power plants in the United States had an average
uncontrolled sulfur emissions potential of 1.8 lb SO2/MMBtu
heat input in 2002. Since 1995, eight new coal-fired electric utility
steam generating units have been built in the United States, and these
units have an average uncontrolled SO2 emission level of 1.6
lb SO2/MMBtu heat input and a maximum of 2.1 lb
SO2/MMBtu heat input. We concluded that new electric utility
steam generating projects will use either IGCC technology, state-of-
the-art SO2 controls, or burn low- and medium-sulfur content
coals to achieve reductions.
New steam generating projects that use IGCC technology will
inherently have only trace SO2 emissions because over 99
percent of the sulfur associated with the coal is removed by the coal-
gasification process. New steam generating units that use fluidized-bed
combustion technology can control SO2 during the combustion
process by coal washing, coal blending, adding limestone into the
fluidized-bed, and installing polishing scrubbers. However, to date,
application of fluidized-bed combustion technology has been limited to
the lower end of the steam generating unit sizes expected for new
electric utility projects (the largest FBC unit built to date is 350
MW). For SO2 controls applied to steam generating units
using pulverized coal combustion technology, control strategies involve
the burning of low sulfur coals, coal washing, coal blending, the use
of post-combustion controls to remove SO2 from the flue
gases, and co-firing with natural gas, low sulfur fuel oil, or biomass.
The majority of new electric utility steam generating units will use
pulverized coal combustion technology. Therefore, using the fuel-
neutral approach discussed earlier, we decided to base the BDT
determination for development of an amended SO2 standard on
application of SO2 control technologies to pulverized coal-
fired steam generating units.
We reviewed the SO2 control technologies currently
available for application to pulverized coal-fired electric utility
steam generating units. We concluded that FGD is BDT for these units.
The type of FGD system used for a given new unit depends on a number of
site-specific factors, including unit size, sulfur content of coal to
be burned in the unit, and the overall economics of each application.
Existing wet FGD systems used for pulverized coal-fired electric
utility steam generating units, especially the scrubber technologies
installed in the last 10 years, are capable of consistently achieving
SO2 removal efficiencies of 95 percent and higher. Multiple
plants have demonstrated that this level of control is achievable on a
long-term basis.
Enhanced wet FGD systems are capable of achieving high removal
efficiencies and can be used for units burning the highest sulfur
content coals. In addition, dry FGD technologies such as lime spray
dryer (LSD) systems can be used to achieve significant reductions in
SO2 emissions under certain conditions. Typically, LSD
systems have been used for smaller size electric utility steam
generating units burning lower sulfur content coals. There are several
LSD systems designed for 90 percent or higher SO2 removal
efficiencies. Based on this information, we concluded that current FGD
systems being installed on new electric utility steam generating units
can achieve SO2 emission levels below the level of the
existing SO2 standard, and that amending this SO2
standard for new electric utility steam generating units is warranted.
To assess the SO2 control performance level of utility
units, we reviewed new and retrofitted facilities with SO2
controls. Since 1995, the Harrison coal-fired power plant in West
Virginia has used a FGD system based on wet scrubbing technology that
has achieved annual SO2 emissions of approximately 1 lb/MWh
gross output from an uncontrolled level of 5.4 lb/MMBtu heat input.
Based on hourly acid rain data from 1997 to 2000, the highest 30-day
average from the three stacks ranged between 1.3 to 1.5 lb
SO2/MWh gross
[[Page 9716]]
output. The Conemaugh facility in Pennsylvania has maintained 30-day
average emissions under 1.4 lb SO2/MWh gross output over the
same period using coal with uncontrolled emissions of 3.4 lb
SO2/MMBtu heat input. Based on the performance of the
Harrison facility, we are selecting a single limit for all fuels of
0.21 lb SO2/MMBtu heat input as the basis for the proposed
standard. We realize many new units will operate below this value, but
the proposed limit would allow the highest sulfur coals (uncontrolled
emissions of 7 lb SO2/MMBtu) to meet the limit using similar
technology as the Harrison facility. Using a gross electrical
generating efficiency of 36 percent, the proposed standard is 250 ng/J
(2.0 lb/MWh) of SO2. Based on the third quarter 2004
emissions data from EPA's Clean Air Markets Division, eleven percent of
existing coal units are presently operating at or below this limit. We
are soliciting comments on the proposed limit and are considering the
range of 120 to 250 ng/J (0.9 to 2.0 lb/MWh) for the final rule.
Of the coals used in existing electric utility plants, 70 percent
could comply with the proposed standard using spray dryers. Eighty nine
percent could meet the standard with conventional wet FGD technology,
and ninety nine percent with enhanced wet scrubbing. Only one percent
of existing coal utilities use coal with uncontrolled SO2
emissions greater than 7 lb/MMBtu. If a utility were to elect to use a
fuel with uncontrolled SO2 emissions above 7 lb/MMBtu heat
input, technology is available that would allow the unit to meet the
proposed standard. Options include physical coal washing, blending with
low sulfur fuels, combining SO2 control technologies like
those applied at the JEA Northside facility, super-critical high-
efficiency boilers, combined heat and power, and gasification. In
addition, emerging SO2 control technologies will allow the
direct use of any fuel in a conventional coal plant without fuel
blending or pretreatment. Therefore, regardless of the sulfur content
of the bituminous, subbituminous, or lignite coal burned by a new
electric utility steam generating unit, SO2 emission control
technologies are available that would allow the unit owner or operator
to comply with the proposed SO2 standard at a reasonable
cost.
Coal refuse (also called waste coal) is a combustible material
containing a significant amount of coal that is reclaimed from refuse
piles remaining at the sites of past or abandoned coal mining
operations. Coal refuse piles are an environmental concern because of
acid seepage and leachate production, spontaneous combustion, and low
soil fertility. Advancements in fluidized-bed combustion technology
allow reclaimed coal refuse to be burned in power plants and
cogeneration facilities. Facilities that burn coal refuse provide
special multimedia environmental benefits by combining the production
of energy with the clean up of coal refuse piles and by reclaiming land
for productive use. Consequently, because of the unique environmental
benefits that coal refuse-fired power plants provide, these units
warrant special consideration so as to prevent the amended NSPS from
discouraging the construction of future coal refuse-fired power plants
in the United States.
We reviewed emissions data and title V permit information for the
existing coal refuse-fired power plants currently operating in the
United States. Based on our review, we concluded that the PM and
NOX emission levels for these facilities were comparable to
the emission levels from other coal-fired electric utility power plants
using similar control technology. Thus, coal refuse-fired electric
utility steam generating units can achieve the same PM and
NOX emission standards being proposed for bituminous,
subbituminous, and lignite coals. However, there is a possibility that
coal refuse from some piles will have sulfur contents at such high
levels that they present potential economic and technical difficulties
in achieving the same SO2 standard that we are proposing for
higher quality coals. Therefore, so as not to preclude the development
of these projects, we are proposing a separate SO2 emission
limit that we concluded is achievable for the full range of coal refuse
piles remaining in the United States. The proposed standard is 0.25 lb
SO2/MMBtu heat input for facilities that burn over 90
percent coal refuse. Using the same baseline efficiency of 36 percent,
the proposed standard is 300 ng/J (2.4 lb/MWh) of SO2 for
units that burn coal refuse. We are requesting comment on the proposed
limit and are considering the range of 180 to 360 ng/J (1.4 to 2.8 lb/
MWh) for the final rule.
3. How Did EPA Select the Proposed NOX Standard?
In 1998, we amended the NOX emission limits for new
electric utility steam generating units built or reconstructed after
July 9, 1997 (63 FR 49444, September 9, 1998). At that time, we
concluded that SCR represented BDT for continuous reduction of
NOX emissions from electric utility steam generating units.
The level of the amended NOX emission limit was selected
based on the performance data of SCR control technology in combination
with combustion controls on coal-fired steam generating units. The
existing NSPS is 200 ng/J of gross output (1.6 lb/MWh) for new units
and 65 ng/J of heat input (0.15 lb/MMBtu) for reconstructed units (63
FR 49444).
We reviewed the NOX control technologies currently
available for application to electric utility steam generating units,
and concluded that SCR remains BDT for continuous reduction of
NOX emissions from these sources. However, since the time we
selected the current NOX emission limits, the number of
electric utility steam generating units in the United States using SCR
control technology has substantially increased. In 2002, more than 50
electric utility steam generating units were operating SCR controls,
with additional facilities installing or planning to install the
technology. In addition, at units operating SCR controls, the
installation of NOX CEMS allows the collection of long-term
data on SCR control performance. As a result, we now have access to
significantly more data on the performance of SCR control technology
than was available to us in 1998.
The design NOX reduction efficiencies of the SCR
controls in use on specific electric utility steam generating units
vary depending on site-specific conditions (e.g., retrofit to existing
units versus new unit applications, facility's air permit requirements,
other NOX combustion controls used), but operating data
indicate that NOX emission reduction levels of 90 percent or
more can consistently be achieved for coal-fired electric utility steam
generating units.
Two units built after the 1998 NOX NSPS amendments for
utility units are the JEA Northside facility in Florida and the
Hawthorn facility in Missouri. Both are operating within their permit
limits of 0.09 lb NOX/MMBtu heat input and 0.08 lb
NOX/MMBtu heat input, respectively. These values are below
the current standard of 1.6 lb/MWh, which is based on 0.15 lb
NOX/MMBtu heat input. Based on the incorporation of
combustion control technologies into new electric utility steam
generating unit designs and the demonstrated SCR performance for
recently built units, we concluded that amending this NOX
standard for new electric utility steam generating units is warranted.
While the WA Parish coal facility in Texas has demonstrated control
of approximately 0.04 lb NOX/MMBtu heat input, we are
proposing a level of 0.11 lb/MMBtu heat input as the basis for the
proposed standard. This emission limit
[[Page 9717]]
allows for the possibility of using fluidized beds and advanced-
combustion controls as an alternative to SNCR or SCR. Advanced
combustion controls reduce compliance costs, parasitic energy
requirements, and ammonia emissions. We converted this value to the
corresponding value in units of lb/MWh using an overall efficiency
factor of 36 percent. Therefore, we are proposing for the
NOX standard a level of 130 ng/J (1.0 lb/MWh) gross
electricity output as determined on a 30-day rolling average. Based on
third quarter 2004 emissions data from EPA's Clean Air Markets
Division, approximately 14 percent of existing units are achieving this
limit. We are soliciting comments on this approach and are particularly
interested in additional data on the achievable NOX levels
of fluidized beds without additional NOX controls and
pulverized coal units with advanced combustion controls. The range of
values we are presently considering for the final rule is 60 to 170 ng/
J (0.47 to 1.3 lb/MWh).
D. How Did EPA Determine the Amended Standards for Industrial-
Commercial-Institutional Steam Generating Units (40 CFR Part 60,
Subparts Db and Dc)?
New source performance standards for industrial-commercial-
institutional steam generating units in the proposed amendments would
apply only to affected sources that begin construction, modification,
or reconstruction after February 28, 2005. In this action, we are
proposing an amended emission limit for PM under 40 CFR part 60,
subparts Db and Dc, and no change to the emission limits for
SO2 and NOX. However, we are requesting public
comments on the concept of adopting a single, fuel-neutral emission
limit for SO2 to replace the current 90 percent reduction
requirement in the final rule. We are also requesting comment on the
possibility of lowering the SO2 emission limits in 40 CFR
part 60, subpart Dc, for units with heat input capacities of 10 MMBtu/
hr to 75 MMBtu/hr and developing NOX emission limits for
units subject to 40 CFR part 60, subpart Dc.
1. How Did EPA Select the Proposed PM Limit?
The current PM standards under 40 CFR part 60, subpart Db, for
industrial, commercial, and institutional boilers greater than 100
MMBtu/hr heat input range from 0.051 lb/MMBtu heat input to 0.2 lb/
MMBtu heat input, depending on the type and amount of fuels burned. The
current PM standards under 40 CFR part 60, subpart Dc, for industrial,
commercial, and institutional boilers with heat input capacities of 30
MMBtu/hr to 100 MMBtu/hr range from 0.051 lb/MMBtu heat input to 0.3
lb/MMBtu heat input, depending on the type and amount of fuels burned.
We are proposing a PM limit of 0.03 lb/MMBtu heat input for units
that burn coal, oil, wood or a mixture of these fuels with other fuels
and have a heat input capacity greater than 30 MMBtu/hr. The emission
limit is based on the use of fabric filters or high efficiency ESP,
which represents BDT. Fabric filters have been shown to achieve greater
than 99 percent reduction in PM emissions and may achieve as high as
99.99 percent reduction for some units.
To determine the appropriate limit, we reviewed boiler permit
limits and emission information gathered for industrial, commercial,
and institutional boilers. Based on this information, we concluded that
new boilers can achieve an emission limit of 0.03 lb/MMBtu heat input
using a fabric filter or high-efficiency ESP. An emission limit of 0.03
lb/MMBtu heat input is achievable by all industrial, commercial, and
institutional boilers considering the wide variety of fuels fired and
the range of operating conditions under which those boilers are run.
The proposed NSPS emission limits would not pose significant new
costs. New industrial-commercial-institutional steam generating units
that are major sources of hazardous air pollutants will be covered also
by the National Emission Standards for Hazardous Air Pollutants
(NESHAP) for industrial, commercial, institutional boilers and process
heaters (40 CFR part 63, subpart DDDDD). The industrial, commercial,
institutional boiler and process heater NESHAP require all boilers with
a heat input greater than 10 MMBtu/hr and firing solid fuels to meet
either a PM limit of 0.025 lb/MMBtu heat input or a total selected
metals limit of 0.0003 lb/MMBtu heat input. Liquid-fired units with
heat inputs greater than 10 MMBtu/hr must meet a PM limit of 0.03 lb/
MMBtu heat input. Accordingly, for most boilers the proposed NSPS would
not impose any additional costs because these units are already
required to comply with equivalent or more stringent emission limits in
the industrial, commercial, institutional boiler and process heater
NESHAP.
However, the industrial, commercial, institutional boiler and
process heater NESHAP also allow several compliance alternatives that
would allow some sources to comply without installing a fabric filter.
These alternatives include demonstrating that emissions are below a
risk threshold, meeting an alternative metals emission limit, or by
demonstrating the metal hazardous air pollutant (HAP) content in the
fuel is below the metals emission limit. A review of the data gathered
for the industrial, commercial, institutional boiler and process heater
NESHAP shows that some wood-fired units are expected to be able to use
the alternative compliance options, because wood has a low HAP-to-PM
ratio. Therefore, the primary impact of the proposed NSPS would be to
require wood-fired boilers to install more efficient controls than
would be needed to demonstrate compliance with the industrial,
commercial, institutional boiler and process heater NESHAP. For wood-
fired boilers, there is a significant flamability risk with fabric
filter bags due to particulate loading. Therefore, we analyzed the cost
and emissions reductions achieved using a high-efficiency ESP to meet
the NSPS limits. Emission test information from industrial, commercial,
institutional boilers and utility boilers shows that ESP can achieve
the same emissions reductions as fabric filters for these units.
We are projecting that 13 wood-fired units with heat inputs larger
than 100 MMBtu/hr will be constructed over the next 5 years. Annual PM
emissions would be reduced by 888 tons per year (tpy), from 1,300 tpy,
based on the current subpart Db, 40 CFR part 60, emission limits, to
412 tpy with the proposed PM emission limit. The incremental annualized
cost of installing and operating an ESP on wood-fired units would be
about $2,300 per ton of PM removed.
For the 30 to 100 million Btu/hr size range, we project that four
wood-fired units will be constructed over the next 5 years. For these
units, annual PM emissions would be reduced by 43 tpy, from about 62
tpy, under the current subpart Dc, 40 CFR part 60, emission limits, to
19 tpy with the proposed PM emission limit. The incremental annualized
cost of installing and operating an ESP on a wood-fired unit would be
$3,200 per ton of PM removed.
2. How Did EPA Select the Proposed SO2 Emission Limit?
The existing SO2 standard for coal- and oil-fired units
larger than 75 MMBtu/hr is 90 percent reduction of potential
SO2 emissions and a maximum emission limit of 1.2 lb/MMBtu
heat input for coal and 0.8 lb/MMBtu heat input for oil. These limits
are based on the use of FGD systems or lime spray dryers. The percent
reduction requirement does not apply to
[[Page 9718]]
units burning fuel oil that have an SO2 emission potential
of 0.5 lb/MMBtu heat input or less. Fluidized bed boilers burning
refuse coal are subject to an 80 percent reduction requirement. For
small boilers (less than 75 MMBtu/hr) the existing NSPS are based on
low sulfur fuels (1.2 lb SO2/MMBtu heat input).
Based on our review, we are proposing to retain the current
SO2 standard for industrial, commercial, and institutional
boilers. In determining BDT, we reviewed the performance of available
control technologies and the permits issued for new coal-fired
industrial, commercial, and institutional boilers constructed since the
publication of 40 CFR part 60, subparts Db and Dc. Based on a review of
the information in the Reasonably Available Control Technology/Best
Available Control Technology/Lowest Achievable Emission Rate (RACT/
BACT/LAER) Clearinghouse, all NSPS units smaller than 75 MMBtu/hr were
issued permits to use low sulfur coal. For units greater than 75 MMBtu/
hr, the technology used was either lime spray dryers, duct injection,
or fluidized-bed boilers with limestone injection. These technologies
have been demonstrated to achieve a 90 percent reduction in
SO2. No industrial-commercial-institutional units were found
to use wet FGD systems.
To determine BDT, we evaluated two options. Option 1 was to amend
subparts Db and Dc, 40 CFR part 60, to adopt a 95 percent reduction
requirement for units larger than 75 MMBtu/hr (the size range currently
required to meet a 90 percent reduction). Option 2 was to amend subpart
Dc, 40 CFR part 60, to require a 90 percent reduction for units smaller
than 75 MMBtu/hr.
Option 1 would achieve a 5th year emission reduction of 1,400 tons
SO2 per year (50 percent reduction from the current NSPS) at
an incremental cost of about $4,000 per ton removed (table 1 of this
preamble). The costs range from $605 per ton removed for some units
larger than 250 MMBtu/hr to $12,000 per ton for some units between 100
and 250 MMBtu/hr. The relatively high incremental cost would occur
because meeting the 95 percent limit would require a technology switch
to more expensive wet FGD systems for many new units. Most new units
currently achieve 90 percent reduction using either sorbent injection
or spray dryers. Under Option 1, these units would switch to wet FGD
systems, because spray dryers and injection technology have not been
demonstrated to achieve a 95 percent SO2 emission reduction.
The annualized cost of wet FGD is higher than for these technologies.
The cost of wet FGD is about 20 percent higher for large coal-fired
units and about 50 percent higher for coal-fired units between 100 and
250 million Btu/hour.
Option 2 would achieve a 5th year emission reduction of 111 tons
SO2 per year (68 percent reduction) for subpart Dc, 40 CFR
part 60, units (table 1 of this preamble). The incremental cost-
effectiveness would range from about $3,000 to more than $8,000 per ton
removed. This cost range represents the cost of applying injection
technologies on units of 50 MMBtu/hr and 25 MMBtu/hr, respectively. The
relatively high incremental cost would occur because this option would
achieve a relatively small additional emissions reductions compared to
the current NSPS. Under the current NSPS, units are achieving
compliance using low sulfur coals with an emission potential of 1.2 lb
SO2/MMBtu heat input. If the NSPS were changed to require a
90 percent reduction, we project that many new units would select
higher sulfur coals because of the reduced fuel cost. For those units
that select a higher sulfur coal, a 90 percent reduction in potential
SO2 emission would result in less than a 90 percent
reduction in emissions compared to the current NSPS.
Considering these potential impacts, we determined that the current
NSPS continues to reflect BDT for 40 CFR part 60, subparts Db and Dc,
industrial, commercial, and institutional boilers. The current
performance levels can be met by using low sulfur fuels for smaller
units and cost-effective control technologies for larger units.
Requiring additional control technology would impose unacceptable
compliance costs that are not warranted for the emissions reductions
that would be achieved.
Table 1.--National 5th Year Impacts of SO2 Controls on Industrial Boilers 2004$
----------------------------------------------------------------------------------------------------------------
Incremental cost-effectiveness
Unit size Emission Annualized ($/ton)
Option range (MMBtu/ reduction cost (million -------------------------------
hr) (tpy) $) Overall Range
----------------------------------------------------------------------------------------------------------------
95 percent \1\.................. 75-250 232 1.68 7,220 6,320-12,060
>250 1,163 1.56 1,340 610-1,960
90 percent \2\ \3\.............. <75 111 0.48 4,280 2,970-8,890
----------------------------------------------------------------------------------------------------------------
\1\ Baseline emissions and emissions reductions used on Option 1 for units greater than 75 MMBtu/hr assume 90
percent SO2 reduction using a mix of medium sulfur content bituminous coal (2.38 lb SO2/MMBtu) and
subituminous coal (1.41 lb SO2/MMBtu).
\2\ Baseline emissions for units less than 75 MMBtu/hr assume bituminous coal with a 1.2 lb SO2/MMBtu emission
potential.
\3\ Emissions reductions were calculated for Option 2 assuming a fuel switch to a 2 to 1 ratio of medium sulfur
coal (1.41 lb/MMBtu) to high sulfur coal (6.81 lb/MMBtu).
3. How Did EPA Select the Proposed NOX Emission Limit?
The current NSPS for NOX apply to fossil fuel-fired
industrial-commercial-institutional steam generating units greater than
100 MMBtu/hr. The NOX emission limit is 0.2 lb
NOX/MMBtu heat input for units burning coal, oil, or natural
gas. Units burning 90 percent or more non-fossil fuel are not required
to meet a NOX emission limit (51 FR 42768). Low heat release
rate units that burn more than 30 percent natural gas or distillate oil
are required to meet a limit of 0.1 lb NOX/MMBtu heat input.
There are currently no NOX emission limits for new
industrial-commercial-institutional steam generating units less than
100 MMBtu/hr.
The current emission limits for fossil fuel-fired units are based
on the application of SCR in combination with combustion controls
(i.e., low-NOX burners). We are not aware of a more
effective NOX control technology for new industrial-
commercial-institutional steam generating units. Based on available
performance data and cost considerations, the Administrator has
concluded that application of SCR with combustion controls represents
the BDT (taking into account costs, non-air quality health and
environmental impacts, and energy requirements) for coal- and residual
oil-fired units.
We, therefore, are proposing to retain the current emission limits
for subpart Db, 40 CFR part 60, units. In the 1998
[[Page 9719]]
amendments, we presented information that showed that SCR can reduce
NOX emissions from coal-fired utility units to 0.15 lb/MMBtu
heat input. However, an emission limit of 0.2 lb/MMBtu heat input was
chosen for industrial-commercial-institutional units based on the cost
associated with applying flue gas treatment to the wide range of boiler
types used in industrial-commercial-institutional applications. Since
the 1998 proposal, only eight coal-fired units subject to subpart Db,
40 CFR part 60, have been permitted. Therefore, only limited
information is available on the performance of SCR on new coal-fired
industrial-commercial-institutional units today. No new performance
information or emissions data have been gathered since the 1998
amendments to indicate that lower limits are consistently achievable
across the full range of boiler types that may be constructed in the
future. In addition, we re-evaluated the costs of SCR. Recent cost
information indicates that the cost of operating SCR technology at
lower levels than the current standard has not decreased significantly
since 1998. We concluded, therefore, that the current emission limits
for fossil fuel-fired units constitute BDT (taking into account costs,
nonair quality health and environmental impacts, and energy
requirements). We are requesting comments and supporting emissions data
on the ability of SCR to achieve lower emission limits on fossil fuel-
fired industrial-commercial-institutional steam generators and the cost
of achieving any lower emission limits.
We are proposing no NOX emission limits for units with
heat input capacities of 100 MMBtu/hr or less (subpart Dc, 40 CFR part
60, units). Information in the RACT/BACT/LAER Clearinghouse shows that
in the last 14 years only one coal-fired unit and 16 solid fuel-fired
units with heat inputs less than 100 MMBtu/hr have been permitted. Over
this same period, 204 units firing natural gas were permitted. This
trend is expected to continue. Consequently, new units under 100 MMBtu/
hr are expected to be predominantly natural gas-or oil-fired.
One possible control option is to adopt an emission limit based on
the performance of low-NOX burners. This option would have
almost no impact on emissions, because most new industrial, commercial,
and institutional boilers today are equipped with low-NOX
burners. The primary impact would be to require the installation of a
CEMS and impose recordkeeping and reporting requirements to demonstrate
that units are continuously meeting the NOX emission limits.
It is unclear that these measures would result in a significant
emissions reductions. We, therefore, concluded that the cost of a CEMS
to monitor low-NOX burners is not reasonable for units
smaller than 100 MMBtu/hr given that little or no emissions reductions
is likely.
We also considered the impact of adopting a 0.2 lb/MMBtu heat input
emission limit based on the use of SCR on coal-fired units (table 2 of
this preamble). This option would reduce NOX emissions from
subpart Dc of 40 CFR part 60 units by 250 tpy, or about a 10 percent
reduction. Given that baseline NOX emissions from gas-fired
units are less than 0.2 lb/million Btu, this limit would have no effect
on emissions for the largest projected subset of units operating
between 10 and 100 million Btu/hr. Gas-fired units, however, would
incur some costs due to monitoring and reporting requirements.
Incremental control costs would range from $3,000 to $17,000 per ton
removed. Based on these costs, and the factors discussed above, we are
proposing not to adopt NOX emission limits for industrial-
commercial-institutional units smaller than 100 MMBtu/hr heat input.
Table 2.--National 5th Year Impacts of NOX Control Option for Industrial Units Subject to 40 CFR Part 60,
Subpart Dc 2004$
----------------------------------------------------------------------------------------------------------------
Emission Incr. cost
Size range (MMBtu/hr) Fuel Number of reduction Annual cost effect. ($/
units (tpy) (million$) ton)
----------------------------------------------------------------------------------------------------------------
30-100........................ Gas............. 61 0 2.42 ..............
Coal............ 1 34 0.20 5,830
Liquid.......... 8 126 0.38 3,040
Wood............ 4 52 0.90 17,320
10-30......................... Gas............. 20 0 0.79 ..............
Liquid.......... 3 21 .14 6,850
Wood............ 2 20 0.18 9,160
-----------------
Total..................... ................ 99 253 5.02 ..............
----------------------------------------------------------------------------------------------------------------
\*\ Liquid and gas units can meet the 0.2 lb/MMBtu limit with a Low-NOX Burner (LNB). Coal and wood units
require an SCR to meet the 0.2 limit.
E. What Technical Corrections Is EPA Proposing?
We are proposing several technical corrections to the current
subparts Da, Db, and Dc of 40 CFR part 60 requirements in the proposed
amendments. The amendments are being proposed to clarify the intent of
the current requirements, correct inaccuracies, and correct oversights
in previous versions that were promulgated.
Heat Recovery Steam Generators
Heat recovery steam generating units are used to recover energy
from the exhaust of combustion turbines.
Some heat recovery steam generators use duct burners or other types
of supplemental heat supply to increase the amount of steam production.
Depending on the heat input capacity of the supplemental heat in a heat
recovery generator, these units may meet the applicability requirements
of 40 CFR part 60, subparts Da, Db, and Dc. However, we recognized that
these units would be more appropriately regulated as part of the
combustion turbine NSPS. In recognition of this, 40 CFR 60.40a(b) and
40 CFR 60.40b(i) provide that when the emission limits for heat
recovery steam generators are incorporated into 40 CFR part 60, subpart
GG, these units would be subject to 40 CFR part 60, subpart GG, and 40
CFR part 60, subparts Da and Db, would no longer apply. This language
was inadvertently left out of 40 CFR part 60, subpart Dc. In a separate
action, we are proposing to amend the NSPS for combustion turbines that
would be codified as subpart KKKK of 40 CFR part 60 instead
[[Page 9720]]
of amending subpart GG of 40 CFR part 60. The proposed subpart will
include requirements for heat recovery steam generators. Therefore, we
are proposing to amend subparts Da, Db, and Dc of 40 CFR part 60 to
require heat recovery steam generators to comply with either subpart GG
of 40 CFR part 60 or subpart KKKK of 40 CFR part 60 as applicable. The
proposed rule language states that ``* * * Heat recovery steam
generators that are associated with combustion turbines and meet the
applicability requirements of subpart KKKK of 40 CFR part 60 of this
part are not subject to this subpart. If the heat recovery steam
generator is subject to this subpart, only emissions resulting from
combustion of fuels in the steam-generating unit are subject to this
subpart. (The combustion turbine emissions are subject to 40 CFR part
60, subpart GG, or 40 CFR part 60, subpart KKKK, as applicable, of this
part.)''
NOX Monitoring Requirements for Units Without NOX
Emission Limits
During the 1998 amendments to 40 CFR part 60, subpart Db, we
amended the monitoring requirements of 40 CFR 60.48b(b) to allow units
that are subject to 40 CFR part 75 (acid rain regulations) to
demonstrate compliance with the NSPS by using CEMS that meet the
requirements of part 75. In making these amendments, we made a drafting
error by inadvertently excluding a phrase from the original NSPS
language. The amended 1998 language could be interpreted to require the
use of NOX CEMs for units that are not subject to the
NOX emission limits of 40 CFR part 60, subpart Db. The
intended language of 40 CFR 60.48b(b) was, ``* * *, the owner or
operator of an affected facility subject to the nitrogen oxides
standards of 60.44b shall comply with either * * * *'' (emphasis added
to the missing phrase). We did not intend for units without a
NOX emission limit to install CEMS for NOX. In
the proposed amendments, we are adding the inadvertently removed
phrase.
Definition of Coal
We are proposing to amend the definition of coal in 40 CFR part 60,
subpart Dc, to reflect the most recent testing methods published by the
ASTM.
Definitions for 40 CFR Part 60, Subpart Da
We are proposing to add definitions of coal, bitimunous coal,
petroleum, and natural gas to 40 CFR part 60, subpart Da, to clarify
applicability and make the rules more uniform.
We are also proposing to amend the definition of boiler operating
day for new utility units to be consistent with the existing definition
for industrial units. The proposed limits reflect the amended procedure
utility units would use to calculate 30-day averages. Our preliminary
analysis of the hourly CEM data from the Harrison facility indicates
that the standards would be approximately 3 percent lower if the
existing definition of boiler-operating day is maintained. The amended
definition also more accurately reflects environmental performance
since less data is excluded from the calculation.
Harmonization of 40 CFR Part 60 and 40 CFR Part 75 Monitoring
Requirements
As a continuation and expansion of the ``turbine initiative'' begun
by EPA in 2001, we are proposing to harmonize portions of the 40 CFR
part 60 continuous emission monitoring regulations with similar
provisions in 40 CFR part 75.
Background. In the late 1990's, the electric utility industry began
planning and constructing numerous combustion turbine projects, to meet
the rising demand for electrical generating capacity in the United
States. Essentially all of these new turbines are subject to both 40
CFR part 60, subpart GG, of the NSPS regulations (40 CFR 60.330 through
60.335) and the Acid Rain regulations (40 CFR part 72 through 40 CFR
part 78). In an August 24, 2001 Federal Register action (66 FR 44622),
EPA estimated that as a result of the new turbine projects, the number
of combustion turbines in the Acid Rain Program would increase from 400
to more than 1,000 within a few years.
The compliance requirements for combustion turbines under the NSPS
and the Acid Rain Program intersect in a number of key places. For
instance, under both programs, the owner or operator of an affected
combustion turbine is accountable for the SO2 and
NOX emissions from the unit. In cases such as this, where
two Federal regulations affect the same unit for the same pollutant(s),
it is always desirable to simplify compliance, to the extent possible.
In view of this, in the previously-cited August 24, 2001 Federal
Register action, EPA requested comments from stakeholders on ways to
streamline and harmonize the 40 CFR part 60 and 40 CFR part 75
regulations, in order to facilitate compliance for sources that are
subject to both sets of rules. EPA's initiative was directed
principally at 40 CFR part 60, subpart GG, combustion turbines that are
also in the Acid Rain Program. However, the Agency also asked for
comments on ``other needed changes to the regulations,'' at places
where the 40 CFR part 60 and 40 CFR part 75 monitoring and reporting
requirements overlap.
EPA received several sets of comments in response to the August 24,
2001, Federal Register action. After careful consideration of these
comments, the Agency proposed substantive amendments to 40 CFR part 60,
subpart GG, on April 14, 2003 (68 FR 18003), incorporating many
suggestions provided by the commenters. The amendments to 40 CFR part
60, subpart GG, were promulgated on July 8, 2004 (69 FR 41346). The
final amendments, which differed little from the proposal, harmonized
the 40 CFR part 60, subpart GG, and 40 CFR part 75 regulations in a
number of key areas. For example:
(1) Amended 40 CFR part 60, subpart GG, allows the use of a
certified 40 CFR part 75 NOX monitoring system to
demonstrate continuous compliance with the NOX emission
limit in 40 CFR 60.332;
(2) If a fuel is documented to be natural gas according to the
criteria in appendix D, 40 CFR part 75, then the 40 CFR part 60,
subpart GG, requirement to monitor the sulfur content of the fuel is
waived; and
(3) A 40 CFR part 60, subpart GG, turbine that combusts fuel oil
may use the oil sampling and analytical methods in appendix D, 40 CFR
part 75 to demonstrate compliance with the 40 CFR part 60, subpart GG,
sulfur-in-fuel limit.
The July 8, 2004 revisions to 40 CFR part 60, subpart GG,
significantly simplify compliance with the 40 CFR part 60 and 40 CFR
part 75 regulations, where both sets of rules apply to the same
combustion turbine. However, the area of overlap between 40 CFR part 60
and 40 CFR part 75 extends beyond combustion turbines. Many electric
utility and industrial boilers regulated under 40 CFR part 60, subparts
D, Da, Db and Dc, are also subject to 40 CFR part 75. Therefore, a more
comprehensive approach to 40 CFR part 60 versus 40 CFR part 75
compliance is needed. A number of stakeholders pointed this out in
their comments on the August 24, 2001, Federal Register action. In
particular, the commenters requested that EPA address the following
problematic areas in the 40 CFR part 60 and 40 CFR part 75 continuous
emission monitoring provisions:
(1) Inconsistent definitions of operating hours;
(2) Inconsistent CEMS data validation criteria;
[[Page 9721]]
(3) Duplicative quality-assurance (QA) test requirements. For
instance, many sources with gas monitors are required to perform both
40 CFR part 75 linearity checks and 40 CFR part 60 cylinder gas audits;
(4) Lack of alternative calibration error and relative accuracy
specifications in 40 CFR part 60 for low-emitting sources;
(5) Inconsistent span and range requirements for gas analyzers; and
(6) For infrequently-operated units, the difficulty of performing
the 40 CFR part 60 calibration drift test over 7 consecutive calendar
days.
Today's proposed amendments would address the chief concerns
expressed by the stakeholders in their comments on the August 24, 2001,
Federal Register action, by amending a number of key sections in 40 CFR
part 60. The proposed amendments are discussed in detail in the
paragraphs below.
Operating Hours and CEMS Data Validation. For all CEMS except
opacity monitors, 40 CFR 60.13(h) in the General Provisions of the NSPS
requires a minimum of four equally-spaced data points to calculate an
hourly emissions average. However, the underlying assumption in the
proposed rule text is that the unit operates for the whole hour, and no
guidelines are given for validating partial operating hours. Section
60.13(h) also appears to conflict with 40 CFR 60.47a(g), subpart Da,
and 40 CFR 60.47b(d) and 40 CFR 60.48b(d), subpart Db, which require
only two valid data points to calculate hourly SO2 and
NOX emission averages. Further, all four of these sections
(i.e., 40 CFR 60.13(h), 40 CFR 60.47a(g), 40 CFR 60.47b(d) and 40 CFR
60.48b(d)) are inconsistent with 40 CFR 75.10(d)(1) and with 40 CFR
60.334(b)(2) of the recently-amended 40 CFR part 60, subpart GG, which
require you to obtain at least one valid data point in each 15-minute
quadrant of the hour in which the unit operates, except for hours in
which required QA and maintenance activities are performed for these
hours, you may calculate the hourly averages from a minimum of two data
points (one in each of two 15-minute quadrants).
Today's proposed amendments would make the CEMS data validation
requirements of 40 CFR 60.13(h), 40 CFR 60.47a(g), 40 CFR 60.47b(d) and
40 CFR 60.48b(d) consistent with 40 CFR 75.10(d)(1) and 40 CFR
60.334(b)(2), as follows:
(1) First, a clear distinction would be made in 40 CFR 60.13(h)
between full and partial operating hours. A full operating hour would
be a clock hour in which the unit operates for 60 minutes, and a
partial operating hour would be one with less than 60 minutes of unit
operation. To calculate an hourly emissions average for a full
operating hour, at least one valid data point would be required in each
of the four 15-minute quadrants of the hour. For a partial operating
hour, at least one valid data point would be required in each 15-minute
quadrant in which the unit operates;
(2) Second, for hours in which required QA or maintenance
activities are performed, 40 CFR 60.13(h) would be amended to allow the
hourly averages to be calculated from a minimum of two data points (if
the unit operates in two or more of the 15-minute quadrants) or one
data point (if the unit operates in only one quadrant of the hour);
(3) Third, 40 CFR 60.13(h) would be amended to require all valid
data points to be used in the calculation of each hourly average;
(4) Fourth, 40 CFR 60.13(h) would require invalidation of any hour
in which a calibration error test is failed, unless in that same hour,
a subsequent calibration error test is passed and sufficient data are
captured after the passed calibration to validate the hour;
(5) Fifth, 40 CFR 60.13(h) would be amended to make it clear that
hourly averages are not to be calculated for certain partial operating
hours, where specified in an applicable NSPS subpart (e.g., hours with
<30 minutes of unit operation are to be excluded from the calculations
under 40 CFR 60.47b(d)); and
(6) Sixth, 40 CFR part 60.47a(g), 40 CFR part 60.47b(d) and 40 CFR
part 60.48b(d) would be amended by removing the provisions that allow
hourly averages to be calculated from only two data points. Rather,
these sections would specify that hourly averages must be calculated
according to amended 40 CFR 60.13(h).
These proposed revisions would provide a single, consistent method
of calculating hourly emission averages from CEMS data for sources that
are subject to both 40 CFR part 60 and 40 CFR part 75. Thus, the same
basic set of CEM data could be used for both 40 CFR part 60 and 40 CFR
part 75 compliance, although certain differences between the two
programs would still remain. For instance, 40 CFR part 75 requires
substitute data to be reported for each hour in which sufficient
quality-assured data is not obtained to validate the hour, whereas 40
CFR part 60 requires these hours to be reported as monitor down time.
Also, 40 CFR part 75 requires a bias adjustment factor (BAF) to be
applied to SO2 and NOX data when a CEMS fails a
bias test, whereas 40 CFR part 60 does not require adjustment of the
emissions data for bias. And for certain partial operating hours, data
that is reported as quality-assured under 40 CFR part 75 is excluded
from the 40 CFR part 60 emission calculations (e.g., see 40 CFR
60.47b(d)). However, these differences between the 40 CFR part 60 and
40 CFR part 75 programs are relatively minor, and in no way detract
from the benefits of having a unified approach to reducing the CEMS
data to hourly averages.
As noted above, EPA is proposing to remove the provisions in 40 CFR
60.47a(g) of subpart Da and in 40 CFR 60.47b(d) and 40 CFR 60.48b(d) of
subpart Db, which require only two valid data points to calculate
hourly SO2 and NOX emission averages. The reason
for this is that these rule texts do not properly communicate the
Agency's original intent. The idea of basing an hourly average on two
data points was first presented in the preamble for subpart Da, 40 CFR
part 60 (44 FR 33581, June 11, 1979). In that preamble, EPA clearly
stated that whenever required QA activities such as daily calibration
error checks are performed, the Agency would allow the hourly average
(assuming it was a full operating hour) to be based on a minimum of two
data points instead of the usual four points required by 40 CFR
60.13(h). This relaxation in the data capture requirement for certain
operating hours was made with the realization that for many CEMS,
calibration checks can take up to 30 minutes, preventing any emissions
data from being collected. However, it was never the Agency's intent to
replace the four-point data capture requirement of 40 CFR 60.13(h) with
a less stringent two-point requirement. The authors of the original 40
CFR part 75 rule understood this, and cited the subpart Da, 40 CFR part
60, preamble as the basis for CFR 75.10(d)(1) (56 FR 63067-68, December
3, 1991). In 40 CFR 75.10(d)(1), at least one valid data point is
required to be obtained in each 15-minute quadrant of the hour in which
the unit operates, except that two data points, separated by at least
15 minutes may be used to calculate an hourly average if required QA
tests or maintenance activities are performed during that hour. More
recently, these same minimum data capture requirements have been
incorporated into 40 CFR 60.334(b)(2) of subpart GG. In view of these
considerations, it is appropriate to remove the two-point minimum data
capture provisions from 40 CFR 60.47a(g), 40 CFR 60.47b(d) and 40 CFR
60.48b(d), and simply to require that the
[[Page 9722]]
SO2 and NOX emission averages be calculated
according to amended 40 CFR 60.13(h).
CEMS Certification and Quality-Assurance. Today's proposed
amendments would add two sections to appendix F, 40 CFR part 60,
pertaining to the on-going quality-assurance requirements for CEMS.
These proposed amendments would apply to sources that are subject to
the QA requirements of both appendix F, 40 CFR part 60 and appendix B,
40 CFR part 75 and would serve a three-fold purpose: (1) To eliminate
duplicative QA test requirements; (2) to allow a single set of data
validation criteria to be applied to the CEMS data; and (3) to allow
certain alternative 40 CFR part 75 performance specifications for low-
emitting sources to be used for 40 CFR part 60 compliance. Today's
proposed amendments also would amend section 8.3.1 of performance
specification 2 (PS-2) in appendix B, 40 CFR part 60, to allow the 7-
day calibration drift test to be performed on 7 consecutive unit
operating days, rather than 7 consecutive calendar days.
EPA proposes to add new sections 4.5 and 5.4 to appendix F, 40 CFR
part 60. Under proposed section 4.5, sources would be allowed to
implement the daily calibration error and calibration adjustment
procedures in sections 2.1.1 and 2.1.3 of appendix B, 40 CFR part 75,
instead of (rather than in addition to) the calibration drift (CD)
assessment procedures in section 4.1 of appendix F, 40 CFR part 60.
Sources electing to use this option would be required to follow the
data validation and out-of-control provisions in sections 2.1.4 and
2.1.5 of appendix B, 40 CFR part 75 instead of the excessive CD and
out-of-control criteria in section 4.3 of appendix F, 40 CFR part 60.
Proposed section 5.4 of appendix F, 40 CFR part 60 would allow
sources to perform the quarterly linearity checks described in section
2.2.1 of appendix B, 40 CFR part 75, instead of (rather than in
addition to) performing the cylinder gas audits described in section
5.1.2 of appendix F, 40 CFR part 60. If a source elected to use this
option, then: (1) The linearity checks would be performed at the
frequency prescribed in section 2.2.1 of appendix B, 40 CFR part 75;
(2) the linearity error specifications in section 3.2 of appendix A, 40
CFR part 75 would have to be met; (3) the data validation criteria in
section 2.2.3 of appendix B, 40 CFR part 75 would be applied in lieu of
the excessive audit inaccuracy criteria in section 5.2 of appendix F,
40 CFR part 60; and (4) the grace period provisions in section 2.2.4 of
appendix B, 40 CFR part 75 would apply.
Proposed section 5.4 of appendix F, 40 CFR part 60 also would allow
sources to perform the on-going quality-assurance relative accuracy
test audit (RATA) of their NOX-diluent and SO2-
diluent monitoring systems according to section 2.3 of appendix B, 40
CFR part 75. If a source elected to use this option, then: (1) The RATA
frequency would be as specified in section 2.3.1 of appendix B, 40 CFR
part 75; (2) the applicable relative accuracy specification in Figure 2
of appendix B, 40 CFR part 75 would have to be met; (3) the data
validation criteria in section 2.3.2 of appendix B, 40 CFR part 75
would be applied in lieu of the excessive audit inaccuracy criteria in
section 5.2 of appendix F, 40 CFR part 60; and (4) the grace period
provisions in section 2.3.3 of appendix B, 40 CFR part 75 would apply.
These proposed amendments to appendix F, 40 CFR part 60 would
greatly simplify compliance without sacrificing data quality.
Currently, sources that are required to perform periodic QA testing
under both appendix F, 40 CFR part 60, and appendix B, 40 CFR part 75,
have two reference frames for CEMS data validation. Neither the CEMS
performance specifications nor the out-of-control criteria are the same
in the two appendices. Generally speaking, the 40 CFR part 75
specifications and data validation criteria are more stringent than
those of 40 CFR part 60. For example, when daily calibrations are
performed, appendix F, 40 CFR part 60, allows the calibration drift of
an SO2 or NOX monitor to exceed 5 percent of span
for 5 consecutive days before the monitor is declared out-of-control.
Under appendix B, 40 CFR part 75, however, a monitor is considered out-
of-control whenever the results of a daily calibration check exceed 5
percent of span. For a 40 CFR part 75 linearity check, three
calibration gases are used (as opposed to two gases for a part 60
cylinder gas audit (CGA)), and the linearity error (LE) specification
(i.e., LE <=5 percent of the reference gas concentration) is much more
stringent than the CGA acceptance criterion of 15 percent. For RATA,
the principal 40 CFR part 75 relative accuracy specification is 10
percent, whereas the appendix F, 40 CFR part 60, specification is 20
percent. Thus, it is safe to say that the data from a CEMS that meets
the quality-assurance requirements of appendix B, 40 CFR part 75 may be
used with confidence for the purposes of 40 CFR part 60 compliance.
Allowing sources to perform the 40 CFR part 75 QA in lieu of
(rather than in addition to) appendix F, 40 CFR part 60, is actually
consistent with section 1.1 of appendix F, 40 CFR part 60, which
encourages sources to ``develop and implement a more extensive QA
program or continue such programs where they already exist.'' It also
harmonizes with 40 CFR 60.47a(c)(2) of subpart Da, 40 CFR 60.48b(b)(2)
of subpart Db, and 40 CFR 60.334(b)(3)(iii) of subpart GG, which allows
certified 40 CFR part 75 NOX monitoring systems to be used
to demonstrate compliance with the applicable NOX emission
limits. However, despite these clear statements in the amendments,
today's proposed amendments to appendix F, 40 CFR part 60 are needed to
eliminate any doubt that meeting the quality-assurance testing
requirements of appendix B, 40 CFR part 75, fully satisfies the
requirements of appendix F, 40 CFR part 60. Many operating permits have
required sources to implement both appendix B, 40 CFR part 75, and
appendix F, 40 CFR part 60, QA procedures for their CEMS. This has
proved to be burdensome, not only because of the previously-mentioned
differences in the specifications and data validation criteria between
the two appendices, but also because 40 CFR part 60 cylinder gas audits
and 40 CFR part 75 linearity checks are so similar in nature (i.e.,
they are essentially two tests of the same type). Since the linearity
check is far more stringent than the CGA, many sources have questioned
why CGA are necessary if quarterly linearity checks are being
performed. Today's proposed amendments would effectively eliminate this
duplicative QA test requirement.
EPA is also proposing to amend section 8.3.1 of PS-2 in appendix B,
40 CFR part 60, to allow the 7-day calibration drift test, which is
performed for the initial certification of a CEMS, to be performed on 7
consecutive unit operating days, rather than 7 consecutive calendar
days. The intent of the proposed amendment is to provide regulatory
relief to infrequently-operated units. Many new sources (particularly
gas turbines) seldom, if ever, operate for 7 consecutive days, making
the 7-day drift test difficult to perform. Allowing the test to be
performed on 7 consecutive operating days should make the test much
easier to complete within the time allotted for initial certification.
The proposed amendment is consistent with section 6.3.1 in appendix A,
40 CFR part 75, and with 40 CFR 60.334(b)(1) of subpart GG.
[[Page 9723]]
CEM Span Values. Today's proposed amendments would amend several
sections of subparts D, Da, Db, and Dc, 40 CFR part 60, pertaining to
CEM span values. The span values for SO2 and NOX
monitors under subparts D, Da, Db and Dc, 40 CFR part 60, are fuel-
specific and are rather prescriptive. For example, subparts D, Da and
Db, 40 CFR part 60, all require a NOX span value of 1000
part per million (ppm) for coal combustion and 500 ppm for oil and gas
combustion. Subpart D, 40 CFR part 60 requires a 1500 ppm
SO2 span value for coal combustion, and subparts Da, Db and
Dc, 40 CFR part 60, all require the span value of the SO2
monitor installed on the control device outlet to be 50 percent of the
maximum estimated hourly potential SO2 emissions for the
type of fuel combusted.
Under 40 CFR part 75, SO2 and NOX span values
are determined in quite a different manner. Sources are required to
determine the maximum potential concentration (MPC) of SO2
or NOX and then to set the span value between 1.00 and 1.25
times the MPC, and select a full-scale measurement range so that the
majority of the data recorded by the monitor will be between 20 and 80
percent of full-scale. The full-scale range must be greater than or
equal to the span value.
Under 40 CFR part 75, units are allowed to determine the MPC values
in a number of different ways, e.g., using a fuel-specific default
value, emission test data, historical CEM data, etc. Units with add-on
SO2 or NOX emission controls are further required
to determine the maximum expected concentration (MEC), which is the
highest concentration expected with the emission controls operating
normally. If the MEC is less than 20 percent of the high scale range,
then a second (low-scale) measurement range is required.
The span value is an important concept in 40 CFR part 60 and 40 CFR
part 75, for two reasons. First, the concentrations of the calibration
gases used for daily calibrations, cylinder gas audits, and linearity
checks are expressed as percentages of the span value (e.g., under 40
CFR part 75, a ``mid'' level gas is 50 to 60 percent of span). Second,
the maximum allowable calibration error (CE) for daily calibration
checks of SO2 and NOX monitors is expressed as a
percentage of the span value (i.e., CE <=5 percent of span). In view of
this, it is essential that the span values be properly-sized, in order
to ensure the accuracy of the CEM measurements. For example, suppose
that a coal-fired unit is subject to both subpart Da, 40 CFR part 60,
and the Acid Rain Program. The owner or operator installs low-
NOX burners to meet the NOX emission limit under
40 CFR part 76, and the actual NOX readings are consistently
between 150 and 200 ppm. Subpart Da, 40 CFR part 60, would require a
span value of 1000 ppm for this unit, but this span would be too high
for 40 CFR part 75, since the NOX data would be consistently
on the lower 20 percent of the measurement scale. Also, by using a span
value of 1000 ppm, the ``control limits'' on daily calibration error
tests would be 5 percent of span, or 50 ppm.
Thus, when measuring a true NOX concentration of 150 ppm,
the NOX monitor could be off by as much as 50 ppm (i.e., by
33 percent) and the monitor would still be considered to be ``in-
control.''
In view of this, it is evident that some of the differences between
the 40 CFR part 60 and 40 CFR part 75 span provisions are not easily
reconcilable, and this raises certain legal and compliance issues. For
instance, in the example cited above, if the owner or operator elects
to use a 500 ppm NOX span value to meet the requirements of
part 75, it is not clear whether he would still be required to maintain
a 1,000 ppm span value to satisfy subpart Da, 40 CFR part 60. To
address these issues, EPA is proposing to amend several sections of
subparts D, Da, Db and Dc, 40 CFR part 60, pertaining to the
determination of SO2 and NOX span values. The
affected sections are 40 CFR 60.45(c)(3) and (4) of subpart D, 40 CFR
60.47a(i)(3), (4), and (5) of subpart Da, 40 CFR 60.47b(e)(3), 40 CFR
60.48b(e)(2) and (3) of subpart Db, and 40 CFR 60.46c(c)(3) and (c)(4)
of subpart Dc. The proposed amendments would allow SO2 and
NOX span values determined in accordance with section 2 of
appendix A, 40 CFR part 75, to be used in lieu of the span values
prescribed by 40 CFR part 60.
Electric Utility Steam Generating Unit
A CHP unit that meets the definition of an electric utility steam
generating unit is subject to 40 CFR part 60, subpart Da. Under 40 CFR
part 60, subpart Da, an electric utility steam generating unit means
``* * * any steam electric generating unit that is constructed for the
purpose of supplying more than one-third of its potential electric
output capacity and more than 25 MW electric output to any utility
power distribution system for sale.'' We recognize that under certain
utility rate structures, it is more economical for CHP facilities to
sell all electric output to the grid and then meter back electric power
for non-utility plant use. The intent of the definition of an electric
utility steam generating unit under subpart Da, 40 CFR part 60, is to
consider net sales and not gross sales to the grid. Therefore, we are
proposing to amend the definition to change ``electric output'' to
``net electric output'' and to define net electric output as ``gross
electric sales to the electric distribution system minus purchased
power on a 30-day rolling average.''
V. Modification and Reconstruction Provisions
Existing steam generating units that are modified or reconstructed
would be subject to today's proposed amendments. Analysis of acid rain
and ozone season data for existing sources indicates that reconstructed
and modified units should be able to achieve the proposed standards.
A modification is any physical or operational change to an existing
facility which results in an increase in the facility's emission rate
(40 CFR 60.14). Changes to an existing facility that do not result in
an increase in the emission rate, either because the nature of the
change has no effect on emission or because additional control
technology is employed to offset an increase in the emission rate, are
not considered modifications. In addition, certain changes have been
exempted under the General Provisions (40 CFR 60.14). These exemptions
include an increase in the hours of operation, addition or replacement
of equipment for emission control (as long as the replacement does not
increase the emission rate), and use of an alternative fuel if the
existing facility was designed to accommodate it.
Rebuilt steam generating units, as defined in section 63.2, would
become subject to the proposed amendments under the reconstruction
provisions, regardless of changes in emission rate. Reconstruction
means the replacement of components of an affected facility such that;
(1) the fixed capital cost of the new components exceeds 50 percent of
the cost of an entirely new steam generating unit of comparable design,
and (2) it is technologically and economically feasible to meet the
applicable standard (40 CFR 60.15).
VI. Summary of Cost, Environmental, Energy, and Economic Impacts
In setting the standards, the CAA requires us to consider
alternative emission control approaches, taking into account the
estimated costs and benefits, as well as the energy, solid waste and
other effects. The EPA requests comment on whether it has identified
the appropriate alternatives and whether the proposed standards
adequately take into consideration the
[[Page 9724]]
incremental effects in terms of emission reductions, energy and other
effects of these alternatives. The EPA will consider the available
information in developing the final rule.
The costs, environmental, energy, and economic impacts are
expressed as incremental differences between the impacts of utility and
industrial-commercial-institutional steam generating units complying
with the proposed amendments and the current NSPS emission limits
(i.e., baseline). The impacts are presented for new steam generating
units constructed over the next 5 years.
For the electric utility sector, The Energy Information
Administration forecasts 1,300 MW of new coal-fired electric utility
steam generating units will be built during the next 5 years. We used
permit data and engineering judgement to determine that the
distribution of these new units by type of coal burned would be as
follows: two bituminous coal-fired units, two subbituminous coal-fired
units, and one coal refuse-fired unit. All new natural gas-fired
electric utility generating units built in the foreseeable future will
most likely be combined cycle units or combustion turbine peaking units
and, thus not subject to subpart Da, 40 CFR part 60, but instead
subject to the NSPS for combustion turbines under 40 CFR part 60,
subpart GG, or subpart KKKK of 40 CFR part 60. Furthermore, because of
fuel supply availability and cost considerations, we assumed that no
new oil-fired electric utility steam generating units will be built
during the next 5 years.
For the industrial-commercial-institutional sector, we project that
87 new steam generating units larger than 100 million Btu per hour will
be built and 99 new steam generating units between 10 and 100 million
Btu per hour will built over the next 5 years. Of these 186 projected
new units, we estimate 8 new coal units, 133 natural gas units, 21
biomass units, 22 liquid fuel units, and 2 non-fossil solid fuel units.
Of the biomass units, only 17 are wood-fired and would be impacted by
the proposed amendments.
The combined impact of the proposed amendments (compared to the
existing NSPS) is to reduce SO2 emissions by about 8,400
tpy, NOX emissions by about 1,400 tpy, and PM emissions by
about 1,500 tpy. The annualized cost of achieving these reductions in
new source emissions is about $6.5 million. The cost and environmental
impacts for each proposed amendment are summarized below.
A. What Are the Impacts for Electric Utility Steam Generating Units?
As discussed earlier, cap and trade programs and new source review
often result in new utility units installing controls beyond what is
required by the existing NSPS. Since only the existing NSPS set
specific limits, we are using those standards as the baseline to be
conservative in our estimating of costs. Actual costs (and benefits) of
the proposed amendments could be less than stated in our analysis.
Also, for pollutants and geographic regions regulated by cap and trade
programs, most new units would install controls as tight or tighter
than the proposed amendments. Therefore, the proposed amendments would
not significantly impact allowance prices or costs for existing utility
sources.
The primary environmental impacts resulting from the proposed
amendments to subpart Da of 40 CFR part 60 for electric utility steam
generating units are further reductions in the amounts of PM,
SO2, and NOX that would be emitted from new units
subject to subpart Da of 40 CFR part 60. Achieving these additional
emissions reductions would increase the costs of installing and
operating controls by approximately 4 percent on a steam generating
unit subject to the proposed standards above those costs for the unit
to comply with the applicable existing standards under subpart Da of 40
CFR part 60. In general, the same types of the PM, SO2, and
NOX controls would be installed on a given unit to comply
with either of the applicable existing or proposed standards. However,
there would be an increase in the capital and annual costs for these
controls to achieve the higher performance levels needed for the
proposed standards due to design modifications and operating changes to
the controls. The estimated nationwide 5-year incremental emissions
reductions and cost impacts for the proposed standards beyond those
estimated for the regulatory baseline are summarized in Table 3 of this
preamble.
Table 3.--National Emissions Reductions and Cost Impacts for Electric Utility Steam Generating Units Subject to
Amended Standards Under Subpart Da of 40 CFR Part 60
[5th Year after proposal]
----------------------------------------------------------------------------------------------------------------
Annual
emissions Total capital Annualized cost
Pollutant reductions investment cost ($ million/yr)
(tpy) ($ million/yr)
----------------------------------------------------------------------------------------------------------------
PM........................................................... 530 $10.4 $2.2
SO2.......................................................... 8,400 $0.9 $0.7
NOX.......................................................... 1,400 $4.9 $1.5
----------------------------------------------------------------------------------------------------------------
1. PM Impacts
The impact of new source review is not included in our baseline so
actual costs (and benefits) of the proposed amendments could be less
than stated in our analysis. The regulatory baseline for PM emissions
is defined to be installation of fabric filters on all new units (i.e.,
electric utility companies would install fabric filters to comply with
the PM standard under the existing NSPS). Design modifications and
operating changes to the fabric filters would be required to achieve
the higher performance level needed to comply with the proposed PM
standard.
Estimated baseline PM emissions from the projected new electric
utility steam generating units are approximately 960 megagrams per year
(Mg/yr) (1,100 tpy). The proposed standards are projected to reduce PM
emissions by 480 Mg/yr (530 tpy). This represents an approximate 50
percent reduction in the growth of PM emissions from new units that
would be subject to the proposed standards.
The nationwide increases in total capital investment costs and the
annual operating costs of the control equipment required to meet the
proposed PM standards over the baseline costs are estimated to be $10.4
million and $2.2 million per year, respectively.
Compliance with the proposed PM standard would increase the
quantity of fly ash collected by the fabric filters over the baseline
levels. Depending on the practices used at a given power plant site,
this would increase the amount of fly ash the utility company
[[Page 9725]]
can recycle as a by-product (e.g., sell as raw material for concrete or
roadway fill material) or increase the amount of fly ash the company
must dispose of as a solid waste either on-site or off-site. No
significant energy impacts, as measured relative to the regulatory
baseline, are expected as a result of the proposed PM standard.
2. SO2 Impacts
The impacts of new source review and the acid rain trading program
are not included in our baseline so actual costs (and benefits) of the
proposed amendments could be less than stated in our analysis. The
regulatory baseline for SO2 emissions is defined to be the
installation of one of three SO2 control configurations,
depending on the type of coal burned. New units burning bituminous coal
were assumed to use pulverized coal-fired boilers equipped with
limestone wet scrubbers with forced oxidation. New units burning low
sulfur, subbituminous coal were assumed to use either spray dryers or
LSFO depending on the boiler size. New units burning lignite or coal
refuse were assumed to use circulating fluidized-bed (CFB) boilers with
limestone addition. Design modifications and operating changes to these
baseline controls would be required to achieve the higher performance
level needed to comply with the proposed SO2 standards.
Estimated baseline SO2 emissions from the projected new
electric utility steam generating units are approximately 14,000 Mg/yr
(16,000 tpy). The proposed standards are projected to reduce
SO2 emissions by 7,600 Mg/yr (8,400 tpy). This represents an
approximate 48 percent reduction in the growth of SO2
emissions from new units that would be subject to the proposed
standards. The proposed limit is approximately 65 percent lower than
the existing limit, but many of the baseline units are over complying
by using low sulfur coals.
The nationwide increases in total capital investment cost and the
annual operating cost of the control equipment required to meet the
proposed standards over the baseline costs are estimated to be $0.9
million and $0.7 million per year, respectively.
For steam generating units using LSFO, compliance with the proposed
SO2 standard would increase the quantity of scrubber sludge
over the baseline levels. Depending on the practices used at a given
power plant site, the resulting scrubber sludge (mostly calcium sulfite
hemihydrate and gypsum) is disposed of in a landfill or is recovered as
a salable by-product (e.g., sold to a wallboard manufacturer). For
those units using a dry scrubber or a CFB with limestone addition, the
dry reaction solids are entrained in the flue gases, along with fly
ash, and then collected by the downstream particulate control device.
Compliance with the applicable proposed SO2 standard would
increase the quantity of solid materials collected by the particulate
control devices over the baseline levels. No significant energy
impacts, as measured relative to the regulatory baseline, are expected
as a result of the proposed SO2 standard.
3. NOX Impacts
The impact of new source review is not included in our baseline so
actual costs (and benefits) of the proposed amendments could be less
than stated in our analysis. The regulatory baseline for NOX
emissions is defined to be installation of SCR controls on all new
pulverized coal-fired units burning bituminous or subbituminous coal,
and no additional NOX controls on the CFB units burning
lignite or coal refuse. Design modifications and operating changes to
the SCR systems would be required to achieve the higher performance
level needed to comply with the proposed NOX standard.
Installation and use of SNCR systems on the CFB units burning lignite
or coal refuse is assumed to be needed to comply with the proposed
NOX standard.
Estimated baseline NOX emissions from the projected new
electric utility steam generating units are approximately 4,700 Mg/yr
(5,200 tpy). The proposed standards are projected to reduce
NOX emissions by 1,200 Mg/yr (1,400 tpy). This represents an
approximate 26 percent reduction in the growth of NOX
emissions from new units that would be subject to the proposed
standards. The proposed limit is approximately 38 percent lower than
the existing limit, but CFB baseline units are over complying with the
existing limit.
The nationwide increases in total capital investment costs and the
annual operating costs of the control equipment required to meet the
proposed standards over the baseline costs are estimated to be $4.9
million and $1.5 million per year, respectively. These cost estimates
may overstate the actual costs to meet the proposed NOX
standard because of the assumption used for the analysis that the CFB
units burning lignite or coal refuse can meet the existing
NOX standard in subpart Da of 40 CFR part 60 without the
need to install flue gas controls for NOX emissions. Thus,
the estimated costs include the full costs of installing SNCR systems
on the CFB units to meet the proposed NOX standard. Also,
data for some western subbituminous coals suggests that the
NOX emission levels from burning these coals will be lower
than the baseline NOX emission levels used for the cost
analysis.
Using nitrogen-based reagents requires operators of SCR and SNCR
systems to closely monitor and control the rate of reagent injection
regardless of the level of an applicable emission standard. If
injection rates are too high, emissions of ammonia from a steam
generating unit using SCR or SNCR may be in the range of 10 to 50 ppm.
No significant energy impacts, as measured relative to the regulatory
baseline, are expected as a result of the proposed NOX
standard.
B. What Are the Impacts for Industrial, Commercial, Institutional
Boilers?
The nationwide increase in annualized costs for new industrial-
commercial-institutional steam generating units greater than 100 MMBtu/
hr heat input is about $2.1 million in the 5th year following proposal
(table 4 of this preamble). This cost reflects the cost for wood-fired
and wood and other fuel co-fired units to comply with the proposed PM
limit. The cost-effectiveness for affected boilers under the proposed
PM standard was $2,400 per ton removed. The proposed standard would
impose no additional costs on fossil fuel-fired boilers.
The nationwide increase in annualized costs for new industrial-
commercial-institutional units operating between 30 and 100 MMBtu/hr is
about $140,000 in the 5th year following proposal. This cost reflects
the control and monitoring cost for wood units to comply with the
proposed PM limit. The range in cost-effectiveness for affected boilers
under the proposed PM standard for subpart Dc of 40 CFR part 60 was
about $3,200 per ton for high moisture wood units to about $3,500 per
ton for dry wood-fired units.
[[Page 9726]]
Table 4.--National Cost and Emission Impacts for Industrial Steam Generating Units
[5-Year impacts]
----------------------------------------------------------------------------------------------------------------
Incremental cost-effectiveness
Number of Emission Annualized ($/ton)
Subpart units reduction cost (million -------------------------------
(tpy) $) Overall Range
----------------------------------------------------------------------------------------------------------------
Db.............................. 13 888 2.11 2,372 2,352-2,577
Dc.............................. 4 43 0.14 3,227 3,142-3,479
----------------------------------------------------------------------------------------------------------------
The range represents the difference in cost-effectiveness between wet and dry wood fuels.
The primary environmental impact resulting from the proposed PM
standards is a reduction in the amount of PM emitted from new steam
generating units. The estimated emissions reductions in the 5th year
following proposal is about 840 Mg/yr (930 tpy) for subparts Db and Dc
of 40 CFR part 60 units combined (about a 70 percent reduction for
wood-fired units).
Secondary emission impacts would occur as a result of the
additional electricity required to operate PM controls. A range of
secondary air impacts for five criteria pollutants is shown in table 5
of this preamble. The range of impacts represents the instances where
all electricity is generated off-site versus on-site.
There would be no significant impacts on the discharges to surface
waters as a result of the proposed amendments to the PM standard.
Fabric filter and ESP technologies do not demand water resources to
control PM.
Solid waste impacts result from disposal of the PM collected in the
fabric filter or ESP control device. The estimated solid waste impacts
are 1,400 Mg/yr (1,500 tpy) for new industrial-commercial-institutional
units at the end of the 5th year following proposal. The estimated
costs of handling the additional solid waste generated are $33,000 for
new industrial-commercial-institutional units greater than 100 MMBtu/hr
and $1,600 for new industrial-commercial-institutional sources
operating between 30 and 100 MMBtu/hr.
The proposed amendments require additional energy to operate fans
on ESP controls. The estimated additional energy requirements are 4.1
million kilowatt hours (kWh) for new industrial-commercial-
institutional units greater than 100 MMBtu/hr and 0.2 million kWh for
new units between 30 and 100 MMBtu/hr. This additional energy
requirement is estimated at about 0.1 percent of the boiler output.
Table 5.--Environmental Impacts of Industrial Units
[5-Year impacts]
----------------------------------------------------------------------------------------------------------------
Secondary air impacts (tpy)
Subpart --------------------------------------------- Solid waste Energy (kWh/
SO2 NOX CO PM VOC (tpy) yr)
----------------------------------------------------------------------------------------------------------------
Db..................................... 0-83 12-50 0-34 1-33 0-2 1,482 4,063,397
Dc..................................... 0-3 0-2 0-1 0-1 0 69 167,860
----------------------------------------------------------------------------------------------------------------
A range of secondary air impacts represent emissions from electricity generated on-site vs. off-site. On-site
generation assumed the use of wood fuel, and off-site generation assumed the use of coal for electricity
generation.
C. Economic Impacts
Utilities. The analysis shows minimal changes in prices and output
for the industries affected by the final rule. The price increase for
baseload electricity is 0.23 percent and the reduction in domestic
production is 0.05 percent. The analysis also shows the impact on the
distribution of electricity supply. First, the construction of the five
units with add-on controls may be delayed; hence the engineering cost
analysis of controls are not incurred by society. Therefore the social
costs of the proposed standard are approximately $0.7 million and
reflect costs associated with existing units bringing higher-cost
capacity online and consumers' welfare losses associated with the price
increases and quantity decreases in the electricity market. However,
this estimate of social costs does not account for the benefits of
emissions reductions associated with this proposed New Source
Performance Standard (NSPS). For more information on these impacts,
please refer to the economic impact analysis in the public docket.
Industrial, Institutional, and Commercial Boilers. Based on
economic impact analysis, the amendments are expected to have a
negligible impact on the prices and production quantities for both the
industry as a whole and the 17 affected entities. The economic impact
analysis shows that there would be less than 0.01 percent expected
price increase for output in the 17 affected entities as a result of
the amendments for wood-fueled industrial boilers, subparts Db and Dc
of 40 CFR part 60. The estimated change in production of affected
output is also negligible with less than a 0.01 percent change
expected. In addition, impacts to affected industries show that prices
of lumber and wood products, as well as paper and allied products,
would not change as a result of implementation of the amendments as
proposed, and output of these types of manufacturing industries would
remain the same. Therefore, it is likely that there is no adverse
impact expected to occur for those industries that produce output
affected by the proposed amendments, such as lumber and wood products
and paper and allied products manufacturing. For further information,
please refer to the economic impact analysis in the public docket.
VII. Request for Comments
We request comments on all aspects of the proposed amendments. All
significant comments received will be considered in the development and
selection of the final amendments. We specifically solicit comments on
additional amendments that are under consideration. These potential
amendments are described below.
Industrial Boiler SO2 Standard. We are requesting
additional information on
[[Page 9727]]
the ability of industrial boilers fueled by inherently low sulfur fuels
to achieve a 90 percent reduction. Preliminary information indicates
that industrial boilers using fuels with inherently low SO2
emissions encounter technical difficulties achieving 90 percent sulfur
removal. With this issue in mind, we are considering replacing the
SO2 percent reduction requirement in subparts Db and Dc of
40 CFR part 60 with a single, fuel-neutral emission limit in the final
rule. Also, we would like comments on whether this change, if it is
made, should be available for existing units or only apply to new
units.
The emission limit could be expressed in either an output-based or
input-based format. Either format would not create disincentives for
the use of inherently low sulfur fuels. In addition, using an emission
limit format exclusively may have benefits for industrial boilers in
terms of compliance flexibility. Our initial analysis indicates that
FGD systems can economically reduce SO2 emissions from
industrial, commercial, and institutional coal-fired boilers to 100 ng/
J (0.24 lb/MMBtu heat input) heat input or less. The corresponding
optional output-based emission limit would be 320 ng/J (2.6 lb
SO2 per MWh) of gross electrical output.
If we adopt a 0.24 lb SO2/MMBtu heat input emission
limit, as we are considering doing, the impacts depend on the mix of
coals that are burned in new industrial boilers. For units burning coal
with an emission potential greater than 2.4 lb SO2/MMBtu
heat input, control costs would be higher and emissions lower than
under the current NSPS because more than a 90 percent reduction in
emissions would be required. For units burning coal with an emission
potential less than 2.4 lb SO2/MMBtu heat input, control
costs would be reduced and allowable emissions would be somewhat higher
than the current NSPS. Industrial boilers using coal with an emission
potential of 2.4 lb SO2/MMBtu heat input would experience no
difference in required control, but compliance costs would be lower
because the testing and monitoring costs of complying with an emission
limitation would be less than for a percent reduction standard, which
requires testing at the inlet and outlet of the control device.
Preliminary analysis shows that a 0.24 lb/MMBtu standard would
reduce emissions by 40 tpy with a small net cost savings. This analysis
is based on the projection of six new coal-fired units with an
SO2 emission potential of 2.4 lb SO2/MMBtu heat
input or less, and one new boiler co-firing coal and wood with an
emission potential of 3.0 lb SO2/MMBtu heat input.
We request comments on the advantages and disadvantages of amending
the current 40 CFR part 60, subpart Db and Dc, standards to an
SO2 emission limitation only and the likely cost and
emissions reductions impacts. We also solicit data on the sulfur
content of coals used by industrial boilers and future market
projections.
If we adopt an emission limit format, we solicit comments on
whether the emission limit should be expressed in an input-based or
output-based format. In the 1998 NSPS amendments, we concluded that an
output-based format provided only limited opportunity for promoting
energy efficiency at subpart Db, 40 CFR part 60, units. In addition, we
concluded that an output-based format could impose additional hardware
and software costs because instrumentation to measure energy output
generally did not exist at industrial-commercial-institutional
facilities. In the case that we decide to replace the percent reduction
requirement for 40 CFR part 60, subpart Db, and 40 CFR part 60, subpart
Dc, units, we solicit comments on the benefits and costs of adopting an
output-based emission limit either as the sole emission limit or as an
optional emission limit.
An alternate approach we are considering and would like comment on
is maintaining the percent reduction requirement and establishing an
alternate emission limit. Under this approach, all units would comply
with either an emissions limit of 0.2 lb SO2/MMBtu or a 95
percent reduction. We would like comments both on this approach and
appropriate limits.
Selection of Optional Output-Based NOX Emission Limit for 40
CFR Part 60, Subpart Db, Units That Generate Electricity
For industrial-commercial-institutional units that generate
electricity, we are considering an optional output-based emission limit
in units of pounds of pollutant per MWh of gross energy output.
Ideally, the output-based emission limit would be based on emissions
data and energy output data that were measured simultaneously. However,
output-based emission data are not readily available for industrial
steam generating units. Most emission test data today are reported
based on energy input, consistent with current State and Federal
compliance reporting requirements. In the absence of measured output-
based data, we would develop the emission limit using input-based
emissions data and a baseline energy generating efficiency.
To develop the emission limit, we would use a baseline gross
electrical generating efficiency of 32 percent, or a corresponding heat
rate of 10.667 MMBtu/MWh. Most existing electric utility steam
generating units achieve an overall efficiency of 29 to 38 percent,
with newer units trending to the upper end of that range. However,
given the diverse use of industrial-commercial-institutional steam
generating unit applications, and since these units are primarily
designed for providing process steam and not optimized for electrical
production, we decided that applying an efficiency of 38 percent (i.e.,
at the high end of the efficiency range) would be unreasonable. The
output-based emission limit was, therefore, calculated by multiplying
the input-based emission limit by the heat rate corresponding to a 32
percent gross electrical generating efficiency. Given a NOX
emission limit of 86 ng/J (0.2 lb/MMBtu heat input) for fossil fuel-
fired units, we are proposing a corresponding output-based emission
limit of 270 ng/J (2.1 lb/MWh). If you choose to comply with the
optional output-based emission limit for your unit, then you must
demonstrate compliance based on a 30-day rolling average. This
averaging period is consistent with the input-based emission limit
requirements, and it provides a sufficient averaging period to account
for any variability in unit operating efficiency.
Applicability of the Industrial-Commercial-Institutional Boiler PM
standard. The existing emission limits for PM in 40 CFR part 60,
subpart Db, and 40 CFR part 60, subpart Dc, apply only to coal, oil,
and wood-fired units. We are considering and requesting comment on
extending the applicability of the proposed NSPS to cover all solid
fuel-fired fuels in the final rule. A review of the BACT/LAER database
revealed that since 1991, construction permits have been issued for
seven units burning bagasse, two units burning hull fuel, and nine
units burning non-fossil fuel (e.g., wastewater sludge and tire-derived
fuel). Emissions data indicate that these fuels are capable of meeting
the same emission limits as coal-fired units. We solicit comment on the
cost, environmental, and economic implications of extending the
applicability of the proposed PM emission limits for 40 CFR part 60,
subpart Db, and 40 CFR part 60, subpart Dc, to all solid fuels.
Assuming use of a mechanical collector as the basis for baseline
controls, preliminary analysis indicates that PM emissions could be
[[Page 9728]]
reduced by 134 tpy at an incremental cost of about $1,700 per ton
removed.
Reporting Requirements for 40 CFR Part 60, Subpart Dc. Natural gas-
fired units and low sulfur oil-fired units fall under the applicability
of 40 CFR part 60, subpart Dc, due to the heat input capacity of the
unit, but have no applicable emission limits. However, subpart Dc of 40
CFR part 60 requires daily fuel usage recordkeeping for natural gas and
low sulfur oil under section 60.48c(g) to ensure that no other fuels
are being burned in combination with them. Since no emission limits
apply to these units, we are considering amending the reporting
requirements in 40 CFR 60.48c(g) of subpart Dc for units permitted to
fire only natural gas or low sulfur oil from daily to monthly. This
reduction in burden is consistent with recordkeeping alternatives
approved by EPA and will reduce the reporting burden for those
facilities that currently report fuel usage on a daily basis.
Output-based PM Emission Limit for 40 CFR Part 60, Subpart Da. The
proposed amendments to 40 CFR part 60, subpart Da, for electric utility
steam generating units would establish output-based emission limits for
SO2 and NOX. Although we prefer to use output-
based formats for all of the emission limits applicable to an electric
utility steam generating unit subject to the proposed standards, the
proposed emission limit for PM retains the heat input format while we
continue to evaluate PM CEMS. We are considering converting the
proposed PM emission limit to an output-based format and requiring PM
CEMS for the final rule.
For more than two decades, CEMS have been used in Europe to monitor
PM emissions from a variety of industrial sources, including electric
utility steam generating units. In the United States, however, PM CEMS
presently are not routinely used to monitor emissions from coal-fired
electric utility steam generating units. However, several electric
utility companies in the United States have now installed or are
planning to install PM CEMS on electric utility steam generating units.
In recognition of the fact that PM CEMS are commercially available,
we have developed and promulgated PS and QA procedures for PM CEMS (69
FR 1786, January 12, 2004). Performance specifications for PM CEMS are
established under PS-11 in appendix B to 40 CFR part 60 for evaluating
the acceptability of a PM CEMS used for determining compliance with the
emission standards on a continuous basis. Additional quality assurance
procedures are established under procedure 2 in appendix F to 40 CFR
part 60 for evaluating the effectiveness of quality control and quality
assurance procedures and the quality of data produced by the PM CEMS.
Based on our analysis of available data, there is no technical
reason that PM CEMS cannot be installed and operate reliably on
electric utility steam generating units. Thus, the availability of PM
CEMS makes establishing an output-based PM emission limit under 40 CFR
part 60, subpart Da, a realistic option. We are requesting comment on
the application of PM CEMS to electric utility steam generating units,
and the use of data from such systems for compliance determinations
under 40 CFR part 60, subpart Da.
For an output-based PM standard, we would convert the proposed PM
emission limit of 0.015 lb/MMBtu heat input to the corresponding value
in units of lb/MWh using an overall electrical generating efficiency of
36 percent. The resulting PM emission limit would be 18 ng/J (0.14 lb/
MWh) gross electricity output as determined on a 30-day rolling average
basis. The unit owner or operator would not be required to conduct the
periodic performance tests required for demonstrating compliance with
the input-based emission limit. In lieu of these performance testing
requirements, under the proposed amendments the owner or operator would
be required to install and operate a PM CEMS and demonstrate compliance
with the alternative PM standard following the same procedures used to
demonstrate compliance with the SO2 and NOX
standards.
Net Output. The proposed output-based emission limits for utility
boilers are based on gross energy output. To provide a greater
incentive for energy efficiency, we would prefer to base output-based
emission limits on net-energy output. But, as explained earlier, we are
proposing to use gross energy output because a net output approach
could result in monitoring difficulties and unreasonable monitoring
costs, particularly at facilities with both affected and unaffected
units. In general, about 6 to 10 percent of station power is used
internally by parasitic loads, but these parasitic loads vary on a
source-by-source basis. At some facilities, the use of a net output-
based emission limit might be more advantageous. We are considering,
therefore, including an optional net output-based emission limit
wherever the proposed amendments have an output-based limit. We would
develop the limit using a 32 to 34 percent net output efficiency to
convert the gross output-based emission limit to a net output-based
emission limit. Therefore, we are requesting comments on publishing
both a gross output-based emission limit and an optional net output-
based emission limit under 40 CFR 60, subpart Da.
Renewable Energy. We are considering adopting a rule provision to
recognize the environmental benefits and encourage the installation of
non-combustion based renewable electricity generation technologies. We
are requesting comments on allowing an affected facility that generates
electricity and installs a renewable generation technology (e.g.,
solar, wind, geothermal, low-impact (small) hydro) to add the electric
output from the renewable energy facility to the output of the affected
facility when calculating compliance with output-based emission limits.
To be eligible, the renewable generation would have to be constructed
during the same time period as the affected facility and be located on
a contiguous property. This provision could increase compliance
flexibility, decrease costs, and contribute to multimedia-pollutant
reduction. We are requesting comment on including such a provision in
40 CFR 60, subpart Da and Db, and on what forms of renewable energy
would quality.
Definition of Boiler-Operating Day. We are considering amending the
definition of boiler-operating day for existing utility units to be
consistent with the proposed definition for new units. This would allow
30-day rolling average emission rates to be calculated consistently
across sources. We are soliciting comments on if this is appropriate
for existing sources.
CEM Availability. In recognition that 40 CFR part 75 requirements
are more stringent than the NSPS and provide incentives to keep
monitors as close to 100 percent as possible, we are intending to
increase NSPS CEM availability. We would like comment on increasing CEM
availability from 70 percent to 95 percent under 40 CFR part 60,
subpart Da for both existing and new units. Data from EPA's Clean Air
Markets Divisions indicates that in 2003 average NOX hourly
CEM availability was 96 percent and average SO2 hourly CEM
availability was 99 percent.
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order 12866 (58 FR 51735, October 4, 1993), we must
determine whether the regulatory action is ``significant'' and,
therefore, subject to
[[Page 9729]]
review by OMB and the requirements of the Executive Order. The
Executive Order defines ``significant regulatory action'' as one that
is likely to result in a action that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, 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 obligations of
recipients thereof; or
(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, it has been
determined that the proposed amendments are a ``significant regulatory
action'' because they raise novel legal or policy issues within the
meaning of paragraph (4) above. Consequently, the proposed amendments
were submitted to OMB for review under Executive Order 12866. Any
written comments from OMB and written EPA responses are available in
the docket (see ADDRESSES section of this preamble).
B. Paperwork Reduction Act
The proposed action does not impose an information collection
burden under the provisions of the Paperwork Reduction Act, 44 U.S.C.
3501 et seq. The proposed amendments result in no changes to the
information collection requirements of the existing standards of
performance and would have no impact on the information collection
estimate of project cost and hour burden made and approved by OMB
during the development of the existing standards of performance.
Therefore, the information collection requests have not been amended.
The OMB has previously approved the information collection requirements
contained in the existing standards of performance (40 CFR part 60,
subparts Da, Db, and Dc) under the provisions of the Paperwork
Reduction Act, 44 U.S.C. 3501 et seq., at the time the standards were
promulgated on June 11, 1979 (40 CFR part 60, subpart Da, 44 FR 33580),
November 25, 1986 (40 CFR part 60, subpart Db, 51 FR 42768), and
September 12, 1990 (40 CFR part 60, subpart Dc, 55 FR 37674). The OMB
assigned OMB control numbers 2060-0023 (ICR 1053.07) for 40 CFR part
60, subpart Da, 2060-0072 (ICR 1088.10) for 40 CFR part 60, subpart Db,
2060-0202 (ICR 1564.06) for 40 CFR part 60, subpart Dc.
Copies of the information collection request document(s) may be
obtained from Susan Auby by mail at U.S. EPA, Office of Environmental
Information, Collection Strategies Division (2822T), 1200 Pennsylvania
Avenue, NW., Washington, DC 20460, by e-mail at [email protected], or
by calling (202) 566-1672. A copy may also be downloaded off the
Internet at http://www.epa.gov/icr.
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedures Act or any other statute unless the agency certifies that
the rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of the proposed amendments on
small entities, small entity is defined as: (1) A small business
according to Small Business Administration size standards by the North
American Industry Classification System (NAICS) category of the owning
entity. The range of small business size standards for the 17 affected
industries ranges from 500 to 750 employees, except for electric
utility steam generating units. In the case of utility boilers the size
standard is 4 million kilowatt-hours of production or less; (2) a small
governmental jurisdiction that is a government of a city, county, town,
school district or special district with a population of less than
50,000; and (3) a small organization that is any not-for-profit
enterprise that is independently owned and operated and is not dominant
in its field.
After considering the economic impacts of today's proposed
amendments on small entities, we conclude that this action will not
have a significant economic impact on a substantial number of small
entities. We have determined for electric utility steam generating
units, that based on the existing inventory for the corresponding NAICS
code and presuming the percentage of entities that are small in that
inventory, estimated to be 3 percent, is representative of the
percentage of small entities owning new utility boilers in the 5th year
after promulgation, that at most, one entity out of five new entities
in the industry may be small entities and thus affected by the proposed
amendments. We have determined for industrial-commercial steam
generating units, based on the existing industrial boilers inventory
for the corresponding NAICS codes and presuming the percentage of small
entities in that inventory is representative of the percentage of small
entities owning new wood-fueled industrial boilers in the 5th year
after promulgation, that between two and three entities out of 17 in
the industry with NAICS code 321 and 322 may be small entities, and
thus affected by the proposed amendments. Based on the boiler size
definitions for the affected industries (subpart Db of 40 CFR part 60:
greater than or equal to 100 MMBtu/hr; subpart Dc of 40 CFR part 60:
10-100 MMBtu/hr), EPA determined that the firms being affected were
likely to fall under the subpart Dc of 40 CFR part 60 boiler category.
These two or three affected small entities are estimated to have annual
compliance costs between $70 and $105 thousand which represents less
than 5 percent of the total compliance cost for all affected wood-fired
industrial boilers. Based on the average employment per facility data
from the U.S. Census Bureau, for the corresponding NAICS codes under
the subpart Db of 40 CFR part 60 and subpart Dc of 40 CFR part 60
categories, the compliance cost of these facilities is expected to be
less than 1 percent of their estimated sales. For more information on
the results of the analysis of small entity impacts, please
[[Page 9730]]
refer to the economic impact analysis in the docket.
Although the proposed NSPS would not have a significant economic
impact on a substantial number of small entities, EPA nonetheless has
tried to reduce the impact of the proposed amendments on small
entities. In the proposed amendments, the Agency is applying the
minimum level of control and the minimum level of monitoring,
recordkeeping, and reporting to affected sources allowed by the CAA.
This provision should reduce the size of small entity impacts. We
continue to be interested in the potential impacts of the proposed
amendments on small entities and welcome comments on issues related to
such impacts.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act (UMRA) of 1995, Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, we
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final actions with ``Federal mandates'' that
may result in expenditures by State, local, and tribal governments, in
the aggregate, or by the private sector, of $100 million or more in any
1 year. Before promulgating an EPA action for which a written statement
is needed, section 205 of the UMRA generally requires us to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective, or least burdensome alternative
that achieves the objectives of the action. The provisions of section
205 do not apply when they are inconsistent with applicable law.
Moreover, section 205 allows us to adopt an alternative other than the
least costly, most cost-effective, or least burdensome alternative if
we publish with the final action an explanation why that alternative
was not adopted.
Before we establish any regulatory requirements that may
significantly or uniquely affect small governments, including tribal
governments, we must develop a small government agency plan under
section 203 of the UMRA. The plan must provide for notifying
potentially affected small governments, enabling officials of affected
small governments to have meaningful and timely input in the
development of our regulatory proposals with significant Federal
intergovernmental mandates, and informing, educating, and advising
small governments on compliance with the regulatory requirements.
We determined that the proposed amendments do not contain a Federal
mandate that may result in expenditures of $100 million or more for
State, local, and tribal governments, in the aggregate, or the private
sector in any 1 year. Thus, the proposed amendments are not subject to
the requirements of section 202 and 205 of the UMRA. In addition, we
determined that the proposed amendments contain no regulatory
requirements that might significantly or uniquely affect small
governments because the burden is small and the regulation does not
unfairly apply to small governments. Therefore, the proposed amendments
are not subject to the requirements of section 203 of the UMRA.
E. Executive Order 13132: Federalism
Executive Order 13132 (64 FR 43255, August 10, 1999), requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by State and local officials in the development of regulatory
policies that have federalism implications.'' ``Policies that have
federalism implications'' is defined in the Executive Order to include
regulations that have ``substantial direct effects on the States, on
the relationship between the national government and the States, or on
the distribution of power and responsibilities among the various levels
of government.''
Under section 6 of Executive Order 13132, we may not issue a
regulation that imposes substantial direct compliance costs, and that
is not required by statute, unless the Federal government provides the
funds necessary to pay the direct compliance costs incurred by State
and local governments, or we consult with State and local officials
early in the process of developing the proposed action. Also, we may
not issue a regulation that has federalism implications and that
preempts State law, unless we consult with State and local officials
early in the process of developing the proposed action.
The proposed amendments do not have federalism implications. They
will not have substantial direct effects on the States, on the
relationship between the national government and the States, or on the
distribution of power and responsibilities among the various levels of
government, as specified in Executive Order 13132. The proposed
amendments will not impose substantial direct compliance costs on State
or local governments, it will not preempt State law. Thus, Executive
Order 13132 does not apply to the proposed amendments.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175, (65 FR 67249, November 9, 2000), requires us
to develop an accountable process to ensure ``meaningful and timely
input by tribal officials in the development of regulatory policies
that have tribal implications.'' ``Policies that have Tribal
implications'' is defined in the Executive Order to include regulations
that have ``substantial direct effects on relationship between the
Federal government and the Indian tribes, or on the distribution of
power and responsibilities between the Federal government and Indian
tribes.''
The proposed amendments do not have tribal implications, as
specified in Executive Order 13175. They will not have substantial
direct effects on tribal governments, on the relationship between the
Federal government and Indian tribes, or on the distribution of power
and responsibilities between the Federal government and Indian tribes,
as specified in Executive Order 13175. Thus, Executive Order 13175 does
not apply to the proposed amendments.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
Executive Order 13045 (62 FR 19885, April 23, 1997), applies to any
action that: (1) Is determined to be ``economically significant'' as
defined under Executive Order 12866, and (2) concerns an environmental
health or safety risk that we have reason to believe may have a
disproportionate effect on children. If the regulatory action meets
both criteria, we must evaluate the environmental health or safety
effects of the planned action on children, and explain why the planned
regulation is preferable to other potentially effective and reasonably
feasible alternatives we considered.
We interpret Executive Order 13045 as applying only to those
regulatory actions that are based on health or safety risks, such that
the analysis required under section 5-501 of the Executive Order has
the potential to influence the regulation. The proposed amendments are
not subject to Executive Order 13045 because they are based on
technology performance and not on health and safety risks. Also, the
proposed amendments are not ``economically significant.''
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution or Use
Executive Order 13211 (66 FR 28355, May 22, 2001) provides that
agencies
[[Page 9731]]
shall prepare and submit to the Administrator of the Office of
Information and Regulatory Affairs, OMB, a Statement of Energy Effects
for certain actions identified as ``significant energy actions.''
Section 4(b) of Executive Order 13211 defines ``significant energy
actions'' as ``* * * any action by an agency (normally published in the
Federal Register) that promulgates or is expected to lead to the
promulgation of a final action or regulation, including notices of
inquiry, advance notices of proposed rulemaking, and notices of
proposed rulemaking: (1)(i) That is a significant regulatory action
under Executive Order 12866 or any successor order, and (ii) is likely
to have a significant adverse effect on the supply, distribution, or
use of energy; or (2) that is designated by the Administrator of the
Office of Information and Regulatory Affairs as a significant energy
action. * * *''
This action is not a ``significant energy action,'' as defined in
Executive Order 13211, because it is not likely to have a significant
adverse effect on the supply, distribution, or energy use. Further, we
concluded that this action is not likely to have any adverse energy
effects.
I. National Technology Transfer Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113, section 12(d)(15 U.S.C. 272
note) directs us to use voluntary consensus standards in our regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., material specifications, test methods, sampling
procedures, business practices) developed or adopted by one or more
voluntary consensus bodies. The NTTAA directs us to provide Congress,
through OMB, explanations when we decide not use available and
applicable voluntary consensus standards.
This action does not involve any new technical standards or the
incorporation by reference of existing technical standards. Therefore,
the consideration of voluntary consensus standards is not relevant to
this action.
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.
Dated: February 9, 2005.
Stephen L. Johnson,
Acting Administrator.
For the reasons cited in the preamble, title 40, chapter I, part 60
of the Code of Federal Regulations 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, et seq.
Subpart A--[Amended]
2. Section 60.13 is amended by revising paragraph (h), to read as
follows:
Sec. 60.13 Monitoring requirements
* * * * *
(h)(1) Owners or operators of all continuous monitoring systems for
measurement of opacity shall reduce all data to 6-minute averages and
for continuous monitoring systems other than opacity to 1-hour averages
for time periods as defined in Sec. 60.2. Six-minute opacity averages
shall be calculated from 36 or more data points equally spaced over
each 6-minute period.
(2) For continuous monitoring systems other than opacity, 1-hour
averages shall be computed as follows:
(i) For a full operating hour (60 minutes of unit operation), at
least four valid data points are required to calculate the hourly
average, i.e., one data point in each of the 15-minute quadrants of the
hour.
(ii) For a partial operating hour (less than 60 minutes of unit
operation), at least one valid data point in each 15-minute quadrant of
the hour in which the unit operates is required to calculate the hourly
average.
(iii) Notwithstanding the requirements of paragraphs (h)(2)(i) and
(h)(2)(ii) of this section, for any operating hour in which required
maintenance or quality-assurance activities are performed:
(A) If the unit operates in two or more quadrants of the hour, a
minimum of two valid data points, separated by at least 15 minutes, is
required to calculate the hourly average; or
(B) If the unit operates in only one quadrant of the hour, at least
one valid data point is required to calculate the hourly average.
(iv) If a daily calibration error check is failed during any
operating hour, all data for that hour shall be invalidated, unless a
subsequent calibration error test is passed in the same hour and
sufficient valid data are recorded after the passed calibration to meet
the requirements of paragraph (h)(2)(iii) of this section.
(v) For each full or partial operating hour, all valid data points
shall be used to calculate the hourly average.
(vi) Data recorded during periods of continuous monitoring system
breakdown, repair, calibration checks, and zero and span adjustments
shall not be included in the data averages computed under this
paragraph.
(vii) Notwithstanding the requirements of paragraph (h)(2)(vi) of
this section, owners and operators complying with the requirements of
Sec. 60.7(f)(1) or (2) must include any data recorded during periods
of monitor breakdown or malfunction in the data averages.
(viii) When specified in an applicable subpart, hourly averages for
certain partial operating hours shall not be computed or included in
the emission averages (e.g. Sec. 60.47b(d)).
(ix) Either arithmetic or integrated averaging of all data may be
used to calculate the hourly averages. The data may be recorded in
reduced or nonreduced form (e.g., ppm pollutant and percent
O2 or ng/J of pollutant).
(3) All excess emissions shall be converted into units of the
standard using the applicable conversion procedures specified in the
applicable subpart. After conversion into units of the standard, the
data may be rounded to the same number of significant digits used in
the applicable subpart to specify the emission limit (e.g., rounded to
the nearest 1 percent opacity).
* * * * *
Subpart D--[Amended]
3. Section 60.45 is amended by revising paragraph (c)(3) to read as
follows:
Sec. 60.45 Emission and fuel monitoring
* * * * *
(c) * * *
(3) For affected facilities burning fossil fuel(s), the span values
for a continuous monitoring system measuring the opacity of emissions
shall be 80, 90, or 100 percent. For a continuous monitoring system
measuring sulfur oxides or nitrogen oxides, the span value shall be
determined using one of the following procedures:
(i)For affected facilities that are not subject to part 75 of this
chapter, SO2 and NOX span values determined as
follows:
[[Page 9732]]
[In parts per million]
------------------------------------------------------------------------
Span value for Span value for
Fossil fuel sulfur dioxide nitrogen oxides
------------------------------------------------------------------------
Gas............................. (\1\) 500
Liquid.......................... 1,000 500
Solid........................... 1,500 1,000
Combinations.................... 1,000+1,500z 500(x+y)+1,000z
------------------------------------------------------------------------
\1\ Not applicable.
Where:
x = the fraction of total heat input derived from gaseous fossil fuel,
and
y = the fraction of total heat input derived from liquid fossil fuel,
and
z = the fraction of total heat input derived from solid fossil fuel.
(ii) For affected facilities that are also subject to part 75 of
this chapter, SO2 and NOX span values determined
according to section 2 in appendix A to part 75 of this chapter may be
used for the purposes of this subpart.
Subpart Da--[Amended]
4. Section 60.40a is amended by revising paragraph (b) to read as
follows:
Sec. 60.40a Applicability and designation of affected facility.
* * * * *
(b) Heat recovery steam generators that are associated with
combined cycle gas turbines burning fuels other than synthetic-coal gas
and that meet the applicability requirements of subpart KKKK of this
part are not subject to this subpart. This subpart will continue to
apply to all other electric utility combined cycle gas turbines that
are capable of combusting more than 73 MW (250 MMBtu/hour) heat input
of fossil fuel in the heat recovery steam generator. If the heat
recovery steam generator is subject to this subpart and the combined
cycle gas turbine burn fuels other than synthetic-coal gas, only
emissions resulting from combustion of fuels in the steam generating
unit are subject to this subpart. (The combustion turbine emissions are
subject to subpart GG or KKKK, as applicable, of this part).
* * * * *
5. Section 60.41a is amended by revising the definitions of
``boiler operating day'' and ``electric utility steam generating
unit,'' and by adding in alphabetical order the definitions of
``bituminous coal,'' ``coal,'' ``cogeneration,'' ``natural gas,'' and
``petroleum'' to read as follows:
Sec. 60.41a Definitions.
* * * * *
Bituminous coal means coal that is classified as bituminous
according to the American Society of Testing and Materials (ASTM)
Standard Specification for Classification of Coals by Rank D38877, 90,
91, 95, or 98a (incorporated by reference--see Sec. 60.17).
* * * * *
Boiler operating day for units constructed, reconstructed, or
modified on or before February 28, 2005, means a 24-hour period during
which fossil fuel is combusted in a steam generating unit for the
entire 24 hours. For units constructed, reconstructed, or modified
after February 28, 2005, boiler operating day means a 24-hour period
between 12 midnight and the following midnight during which any fuel is
combusted at any time in the steam generating unit. It is not necessary
for fuel to be combusted the entire 24-hour period.
* * * * *
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388-77, 90, 91, 95, or 98a, Standard Specification
for Classification of Coals by Rank (incorporated by reference--see
Sec. 60.17), coal refuse, and petroleum coke. Synthetic fuels derived
from coal for the purpose of creating useful heat, including but not
limited to solvent-refined coal, gasified coal, coal-oil mixtures, and
coal-water mixtures are included in this definition for the purposes of
this subpart.
* * * * *
Cogeneration means a facility that simultaneously produces both
electrical (or mechanical) and useful thermal energy from the same
primary energy source.
* * * * *
Electric utility steam generating unit means any steam electric
generating unit that is constructed for the purpose of supplying more
than one-third of its potential electric output capacity and more than
25 MW net-electrical output to any utility power distribution system
for sale. For the purpose of this subpart, net-electric output is the
gross electric sales to the utility power distribution system minus
purchased power on a 30-day rolling average. Also, any steam supplied
to a steam distribution system for the purpose of providing steam to a
steam-electric generator that would produce electrical energy for sale
is considered in determining the electrical energy output capacity of
the affected facility.
* * * * *
Natural gas means a naturally occurring mixture of hydrocarbon and
nonhydrocarbon gases found in geologic formations beneath the earth's
surface, of which the principal constituent is methane; or liquid
petroleum gas, as defined by the American Society for Testing and
Materials in ASTM D1835-82, 86, 87, 91, or 97, ``Standard Specification
for Liquid Petroleum Gases'' (Incorporated by reference--see Sec.
60.17).
* * * * *
Petroleum means crude oil or petroleum or a liquid fuel derived
from crude oil or petroleum, including distillate and residual oil.
* * * * *
6. Section 60.42a is amended by revising the introductory text in
paragraph (a) and adding paragraph (c) to read as follows:
Sec. 60.42a Standard for particulate matter.
(a) On and after the date on which the 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,
reconstruction, or modification commenced before or on February 28,
2005, any gases that contain particulate matter in excess of:
* * * * *
(c) On and after the date on which the 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,
reconstruction, or modification commenced after February
[[Page 9733]]
28, 2005, any gases that contain particulate matter in excess of 6.4
ng/J (0.015 lb/MMBtu) heat input derived from the combustion of solid,
liquid, or gaseous fuel.
7. Section 60.43a is amended by revising the introductory text in
paragraphs (a) and (b) and adding paragraphs (i) and (j) to read as
follows:
Sec. 60.43a Standard for sulfur dioxide.
(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 which
combusts solid fuel or solid-derived fuel and for which construction,
reconstruction, or modification commenced before or on February 28,
2005, except as provided under paragraphs (c), (d), (f) or (h) of this
section, any gases that contain sulfur dioxide in excess of:
* * * * *
(b) 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 which
combusts liquid or gaseous fuels (except for liquid or gaseous fuels
derived from solid fuels and as provided under paragraphs (e) or (h) of
this section) and for which construction, reconstruction, or
modification commenced before or on February 28, 2005, any gases that
contain sulfur dioxide in excess of:
* * * * *
(i) On and after the date on which the 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,
reconstruction, or modification commenced after February 28, 2005, any
gases that contain sulfur dioxide in excess of 250 ng/J (2.0 lb/MWh)
gross energy output, based on a 30-day rolling average, except as
provided under paragraph (j) of this section.
(j) On and after the date on which the 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 that burns over 90
percent (by heat input) coal refuse and for which construction,
reconstruction, or modification commenced after February 28, 2005, any
gases that contain sulfur dioxide in excess of 300 ng/J (2.4 lb/MWh)
gross energy output, based on a 30-day rolling average.
8. Section 60.44a is amended by revising paragraph (d) and adding
paragraph (e) to read as follows:
Sec. 60.44a Standard for nitrogen oxides.
* * * * *
(d)(1) On and after the date on which the initial performance test
required to be conducted under Sec. 60.8 is completed, no new source
owner or operator subject to the provisions of this subpart shall cause
to be discharged into the atmosphere from any affected facility for
which construction commenced after July 9, 1997 but before or on
February 28, 2005, any gases that contain nitrogen oxides (expressed as
NO2) in excess of 200 ng/J (1.6 lb/MWh) gross energy output,
based on a 30-day rolling average, except as provided under Sec.
60.46a(k)(1).
(2) On and after the date on which the initial performance test
required to be conducted under Sec. 60.8 is completed, no existing
source owner or operator subject to the provisions of this subpart
shall cause to be discharged into the atmosphere from any affected
facility for which reconstruction commenced after July 9, 1997 but
before or on February 28, 2005, any gases that contain nitrogen oxides
(expressed as NO2) in excess of 65 ng/J (0.15 lb/MMBtu) heat
input, based on a 30-day rolling average.
(e) On and after the date on which the initial performance test
required to be conducted under Sec. 60.8 is completed, no new source
owner or operator subject to the provisions of this subpart shall cause
to be discharged into the atmosphere from any affected facility for
which construction, reconstruction, or modification commenced after
February 28, 2005, any gases that contain nitrogen oxides (expressed as
NO2) in excess of 130 ng/J (1.0 lb/MWh) gross energy output,
based on a 30-day rolling average, except as provided under Sec.
60.46a(k)(1).
9. Section 60.46a is amended by revising paragraph (i) and adding
paragraph (l) to read as follows:
Sec. 60.46a Compliance provisions.
* * * * *
(i) Compliance provisions for sources subject to Sec. 60.44a(d)(1)
or (e). The owner or operator of an affected facility subject to Sec.
60.44a(d)(1) or (e) shall calculate NOX emissions by
multiplying the average hourly NOX output concentration,
measured according to the provisions of Sec. 60.47a(c), by the average
hourly flow rate, measured according to the provisions of Sec.
60.47a(l), and dividing by the average hourly gross energy output,
measured according to the provisions of Sec. 60.47a(k).
* * * * *
(l) Compliance provisions for sources subject to Sec. 60.43a(i) or
(j). The owner or operator of an affected facility subject to Sec.
60.44a(i) or (j) shall calculate SO2 emissions by
multiplying the average hourly SO2 output concentration,
measured according to the provisions of Sec. 60.47a(b), by the average
hourly flow rate, measured according to the provisions of Sec.
60.47a(l), and divided by the average hourly gross energy output,
measured according to the provisions of Sec. 60.47a(k).
10. Section 60.47a is amended by:
a. Revising paragraph (b)(2);
b. Adding paragraph (b)(4);
c. Revising paragraph (g); and
d. Adding new sentences at the end each of the following
paragraphs: (i)(3), (i)(4), and (i)(5) to read as follows:
Sec. 60.47a Emission monitoring.
* * * * *
(b) * * *
(1) * * *
(2) For a facility that qualifies under the provisions of Sec.
60.43a(d), (i), or (j), sulfur dioxide emissions are only monitored as
discharged to the atmosphere.
(3) * * *
(4) If the owner or operator has installed a sulfur dioxide
emission rate continuous emission monitoring system (CEMS) to meet the
requirements of part 75 of this chapter and is continuing to meet the
ongoing requirements of part 75 of this chapter, that CEMS may be used
to meet the requirements of this section, except that the owner or
operator shall also meet the requirements of Sec. 60.49a. Data
reported to meet the requirements of Sec. 60.49a shall not include
data substituted using the missing data procedures in subpart D of part
75 of this chapter, nor shall the data have been bias adjusted
according to the procedures of part 75 of this chapter.
* * * * *
(g) The 1-hour averages required under Sec. 60.13(h) are expressed
in ng/J (lb/million Btu) heat input and used to calculate the average
emission rates under Sec. 60.46a. The 1-hour averages are calculated
using the data points required under Sec. 60.13(h)(2).
* * * * *
(i) * * *
(3) For affected facilities burning only fossil fuel, the span
value for continuous monitoring system for measuring opacity is between
60 and 80 percent. For a continuous monitoring
[[Page 9734]]
system measuring nitrogen oxides, the span value shall be determined
using one of the following procedures:
(i) For affected facilities that are not subject to part 75 of this
chapter, NOX span values determined as follows:
------------------------------------------------------------------------
Span value for
Fossil fuel nitrogen oxides
(ppm)
------------------------------------------------------------------------
Gas................................................. 500
Liquid.............................................. 500
Solid............................................... 1,000
Combination......................................... 500 (x+y)+1,000z
------------------------------------------------------------------------
Where:
x is the fraction of total heat input derived from gaseous fossil fuel,
y is the fraction of total heat input derived from liquid fossil fuel,
and
z is the fraction of total heat input derived from solid fossil fuel.
(ii) For affected facilities that are also subject to part 75 of
this chapter, NOX span values determined according to
section 2 in appendix A to part 75 of this chapter may be used for the
purposes of this subpart.
(4) * * * NOX span values that are computed under part
75 of this chapter and used for the purposes of this subpart shall be
rounded off according to section 2 in appendix A to part 75 of this
chapter.
(5) * * * Alternatively, if the affected facility is also subject
to part 75 of this chapter, SO2 span values determined
according to section 2 in appendix A to part 75 of this chapter may be
used for the purposes of this subpart.
* * * * *
Subpart Db--[Amended]
11. Section 60.40b is amended by revising paragraph (i) to read:
Sec. 60.40b Applicability and delegation of authority.
* * * * *
(i) Heat recovery steam generators that are associated with
combined cycle gas turbines and that meet the applicability
requirements of subpart KKKK of this part are not subject to this
subpart. This subpart will continue to apply to all other heat recovery
steam generators that are capable of combusting more than 29 MW (100
million Btu/hour) heat input of fossil fuel. If the heat recovery steam
generator is subject to this subpart, only emissions resulting from
combustion of fuels in the steam generating unit are subject to this
subpart. (The gas turbine emissions are subject to subpart GG or KKKK,
as applicable, of this part).
* * * * *
12. Section 60.41b is amended by adding the definition of
``cogeneration'' in alphabetical order to read as follows:
Sec. 60.41b Definitions.
* * * * *
Cogeneration means a facility that simultaneously produces both
electrical (or mechanical) and useful thermal energy from the same
primary energy source.
* * * * *
13. Section 60.43b is amended by adding paragraph (h) to read as
follows:
Sec. 60.43b Standard for particulate matter.
* * * * *
(h) On or after the date on which the initial performance test is
completed or is required to be completed under 60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification after February
28, 2005, and that combusts coal, oil, wood, a mixture of these fuels,
or a mixture of these fuels with any other fuels shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain particulate matter emissions in excess of 13 ng/J (0.03
lb/million Btu) heat input. Affected facilities subject to this
paragraph are also subject to paragraphs (f) and (g) of this section.
14. Section 60.47b is amended by revising paragraph (d) and adding
a new sentence at the end of paragraph (e)(3) to read as follows:
Sec. 60.47b Emission monitoring for sulfur dioxide
* * * * *
(d) The 1-hour average sulfur dioxide emission rates measured by
the CEMS required by paragraph (a) of this section and required under
Sec. 60.13(h) is expressed in ng/J or lb/million Btu heat input and is
used to calculate the average emission rates under Sec. 60.42(b). Each
1-hour average sulfur dioxide emission rate must be based on 30 or more
minutes of steam generating unit operation. The hourly averages shall
be calculated according to Sec. 60.13(h)(2).
Hourly sulfur dioxide emission rates are not calculated if the
affected facility is operated less than 30 minutes in a given clock
hour and are not counted toward determination of a steam generating
unit operating day.
(e) * * *
(3) * * * Alternatively, if the affected facility is also subject
to part 75 of this chapter, SO2 span values determined
according to section 2 in appendix A to part 75 of this chapter may be
used for the purposes of this subpart.
* * * * *
15. Section 60.48b is amended by revising paragraphs (b)
introductory text, (d), and (e)(2), and adding a new sentence at the
end of paragraph (e)(3) to read as follows:
Sec. 60.48b Emission monitoring for particulate matter and nitrogen
oxides.
* * * * *
(b) Except as provided under paragraphs (g), (h), and (i) of this
section, the owner or operator of an affected facility subject to a
nitrogen oxides standard under 60.44b shall comply with either
paragraphs (b)(1) or (b)(2) of this section.
* * * * *
(d) The 1-hour average nitrogen oxides emission rates measured by
the continuous nitrogen oxides monitor required by paragraph (b) of
this section and required under Sec. 60.13(h) shall be expressed in
ng/J or lb/million Btu heat input and shall be used to calculate the
average emission rates under Sec. 60.44b. The 1-hour averages shall be
calculated using the data points required under Sec. 60.13(h)(2).
(e) * * *
(2) For affected facilities combusting coal, oil, or natural gas,
the span value for nitrogen oxides shall be determined using one of the
following procedures:
(i) For affected facilities that are not subject to part 75 of this
chapter, NOX span values determined as follows:
------------------------------------------------------------------------
Span value for
Fossil fuel nitrogen oxides
(ppm)
------------------------------------------------------------------------
Natural gas......................................... 500
Oil................................................. 500
Coal................................................ 1,000
Mixture............................................. 500(x+y)+1,000z
------------------------------------------------------------------------
where:
x is the fraction of total heat input derived from natural gas,
y is the fraction of total heat input derived from oil, and
z is the fraction of total heat input derived from coal.
(ii) For affected facilities that are also subject to part 75 of
this chapter, NOX span values determined according to
section 2 in appendix A to part 75 of this chapter may be used for the
purposes of this subpart.
(3) * * * NOX span values that are computed under part
75 of this chapter and used for the purposes of this subpart shall be
rounded off according to section 2 in appendix A to part 75 of this
chapter.
* * * * *
[[Page 9735]]
Subpart Dc--[Amended]
16. Section 60.40c is amended by adding paragraph (e) to read as
follows:
Sec. 60.40c Applicability and delegation of authority.
* * * * *
(e) Heat recovery steam generators that are associated with
combined cycle gas turbines and meet the applicability requirements of
subpart KKKK of this part are not subject to this subpart. This subpart
will continue to apply to all other heat recovery steam generators that
are capable of combusting more than or equal to 2.9 MW (10 million Btu/
hour) heat input of fossil fuel but less than or equal to 29 MW (100
million Btu/hr) heat input of fossil fuel. If the heat recovery steam
generator is subject to this subpart, only emissions resulting from
combustion of fuels in the steam generating unit are subject to this
subpart. (The gas turbine emissions are subject to subpart GG or KKKK,
as applicable, of this part).
17. Section 60.41c is amended by revising the definition of coal to
read as follows:
Sec. 60.41c Definitions.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388-77, 90, 91, 95, or 98a, Standard Specification
for Classification of Coals by Rank (IBR--see Sec. 60.17), coal
refuse, and petroleum coke. Coal-derived synthetic fuels derived from
coal for the purposes of creating useful heat, including but not
limited to solvent refined coal, gasified coal, coal-oil mixtures, and
coal-water mixtures, are also included in this definition for the
purposes of this subpart.
* * * * *
18. Section 60.43c is amended by adding paragraph (e) to read as
follows:
Sec. 60.43c Standard for particulate matter.
* * * * *
(e) On or after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification after February
28, 2005, and that combusts coal, oil, wood, a mixture of these fuels,
or a mixture of these fuels with any other fuels shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain particulate matter emissions in excess of 13 ng/J (0.03
lb/million Btu) heat input. Affected facilities subject to this
paragraph, are also subject to the requirements of paragraphs (c) and
(d) of this section.
19. Section 60.46c is amended by adding a new sentence at the end
of paragraphs (c)(3) and (c)(4) to read as follows:
* * * * *
(c) * * *
(3) * * * Alternatively, if the affected facility is also subject
to part 75 of this chapter, SO2 span values determined
according to section 2 in appendix A to part 75 of this chapter may be
used for the purposes of this subpart.
(4) * * * Alternatively, for affected facilities that are also
subject to part 75 of this chapter, SO2 span values
determined according to section 2 in appendix A to part 75 of this
chapter may be used for the purposes of this subpart.
* * * * *
Appendix B--[Amended]
20. Appendix B to part 60 is amended by adding a new sentence at
the end of section 8.3.1 in Performance Specification 2, to read as
follows:
Appendix B to Part 60--Performance Specifications
* * * * *
Performance Specification 2--Specifications and Test Procedures for
SO2 and NOX Continuous Emission Monitoring
Systems in Stationary Sources
* * * * *
8.3.1 * * * Alternatively, the CD test may be conducted over 7
consecutive unit operating days, rather than 7 consecutive calendar
days.
* * * * *
Appendix F--[Amended]
21. Appendix F to part 60 is amended by adding sections 4.5 and
5.4, to read as follows:
Appendix F to Part 60--Quality Assurance Procedures
* * * * *
4.5 Alternative CD Assessment. For an affected facility that is
also subject to the monitoring and reporting requirements of part 75
of this chapter, the owner or operator may implement the daily
calibration error test and calibration adjustment procedures
described in sections 2.1.1 and 2.1.3 of appendix B to part 75 of
this chapter, instead of the CD assessment procedures in section 4.1
of this appendix. If this option is selected, the data validation
and out-of-control provisions in sections 2.1.4 and 2.1.5 of
appendix B to part 75 of this chapter shall be followed instead of
the excessive CD and out-of-control criteria in section 4.3 of this
appendix.
* * * * *
5.4 Alternative Data Accuracy Assessment. If an affected
facility is also subject to the monitoring and reporting
requirements of part 75 of this chapter, and if emissions data are
reported on a year-round basis under Sec. 75.64 or Sec. 75.74(b)
of this chapter, the owner or operator may implement the following
alternative data accuracy assessment procedures:
5.4.1 Linearity Checks. Instead of performing the cylinder gas
audits described in section 5.1.2 of this appendix, the owner or
operator may perform quarterly linearity checks of the
SO2, NOX, CO2 and O2
monitors required by this part, in accordance with section 2.2.1 of
appendix B to part 75 of this chapter. If this option is selected:
5.4.1.1 The frequency of the linearity checks shall be as
specified in section 2.2.1 of appendix B to part 75 of this chapter;
and
5.4.1.2 The applicable linearity specifications in section 3.2
of appendix A to part 75 of this chapter shall be met; and
5.4.1.3 The data validation and out-of-control criteria in
section 2.2.3 of appendix B to part 75 of this chapter shall be
followed instead of the excessive audit inaccuracy and out-of-
control criteria in section 5.2 of this appendix; and
5.4.1.4 The grace period provisions in section 2.2.4 of appendix
B to part 75 of this chapter shall apply.
5.4.2 Relative Accuracy Test Audits. Instead of following the
procedures in section 5.1.1 of this appendix, the owner or operator
may perform RATA of the NOX-diluent or SO2-
diluent CEMS required by this part (or both), in accordance with
section 2.3 of appendix B to part 75 of this chapter. If this option
is selected for a particular CEMS:
5.4.2.1 The frequency of the RATA shall be as specified in
section 2.3.1 of appendix B to part 75; and
5.4.2.2 The applicable relative accuracy specifications shown in
Figure 2 in appendix B to part 75 of this chapter shall be met; and
5.4.2.3 The data validation and out-of-control criteria in
section 2.3.2 of appendix B to part 75 of this chapter shall be
followed instead of the excessive audit inaccuracy and out-of-
control criteria in section 5.2 of this appendix; and
5.4.2.4 The grace period provisions in section 2.3.3 of appendix
B to part 75 of this chapter shall apply.
[FR Doc. 05-2996 Filed 2-25-05; 8:45 am]
BILLING CODE 6560-50-P