[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
----------------------------------------------------------------------------------------------------------------
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.
----------------------------------------------------------------------------------------------------------------

    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

[[Page 9709]]

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