Document ID: EPA-HQ-OAR-2005-0031-0176
Agency: epa
Document Type: Rule
Title: 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
Posted Date: 2006-02-27T14:26:58Z

[Federal Register: February 27, 2006 (Volume 71, Number 38)]
[Rules and Regulations]               
[Page 9865-9886]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr27fe06-15]                         

[[Page 9865]]

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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, 
Industrial-Commercial-Institutional Steam Generating Units, and Small 
Industrial-Commercial-Institutional Steam Generating Units; Final Rule

[[Page 9866]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2005-0031; FRL-8033-3]
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: Final rule; amendments.

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SUMMARY: Pursuant to section 111(b)(1)(B) of the Clean Air Act (CAA), 
EPA has reviewed the emission standards for nitrogen oxides 
(NOX), sulfur dioxide (SO2), and particulate 
matter (PM) contained in the new source performance standards (NSPS) 
for electric utility steam generating units and industrial-commercial-
institutional steam generating units. EPA proposed amendments to 40 CFR 
part 60, subparts Da, Db, and Dc, on February 28, 2005. This action 
reflects EPA's responses to issues raised by commenters, and 
promulgates the amended standards of performance.
    The final rule amendments revise the existing standards for PM 
emissions by reducing the numerical emission limits for both utility 
and industrial-commercial-institutional steam generating units and 
revise the existing standards for NOX emissions by reducing 
the numerical emission limits for utility steam generating units. The 
amendments also revise the standards for SO2 emissions for 
both electric utility and industrial-commercial-institutional steam 
generating units. The numerical standard for electric utility steam 
generating units has been reduced, and the maximum percent reduction 
requirement has been increased. A numerical standard has been added for 
units presently subject to the NSPS and new industrial-commercial-
institutional steam generating units, and the maximum percent reduction 
requirement for new units has been increased. Both utility and 
industrial steam generating units can either meet a numerical limit or 
demonstrate a percent reduction.
    Several technical clarifications and compliance alternatives have 
been added to the existing provisions of the current rules.

DATES: The final rule amendments are effective on February 27, 2006.

ADDRESSES: Docket: EPA has established a docket for this action under 
Docket ID No. EPA-HQ-OAR-2005-0031. All documents in the docket are 
listed on the Internet at http://www.regulations.gov. Although listed 

in the index, some information is not publicly available, e.g., 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 
through http://www.regulations.gov or in hard copy at the Air and 

Radiation Docket, Docket ID No. EPA-HQ-2004-0490, EPA/DC, EPA West, 
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 Air 
and Radiation Docket Center is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Mr. Christian Fellner, Energy 
Strategies Group, Sector Policies and Programs Division (C439-01), U.S. 
EPA, Research Triangle Park, North Carolina 27711; telephone number: 
(919) 541-4003; e-mail fellner.christian@epa.gov.

SUPPLEMENTARY INFORMATION: Regulated Entities. Categories and entities 
potentially regulated by the final rule amendments are new, 
reconstructed, and modified electric utility steam generating units and 
new, reconstructed, and modified industrial-commercial-institutional 
steam generating units. The final rule amendments will 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, or                          211              13  Extractors of crude petroleum and
 institutional facility using a boiler as                                     natural gas.
 defined in 60.40b or 60.40c.
                                                        321              24  Manufacturers of lumber and wood
                                                                              products.
                                                        322              26  Pulp and paper mills.
                                                        325              28  Chemical manufacturers.
                                                        324              29  Petroleum refiners and
                                                                              manufacturers of coal products.
                                              316, 326, 339              30  Manufacturers of rubber and
                                                                              miscellaneous plastic products.
                                                        331              33  Steel works, blast furnaces.
                                                        332              34  Electroplating, plating, polishing,
                                                                              anodizing, and coloring.
                                                        336              37  Manufacturers of motor vehicle
                                                                              parts and accessories.
                                                        221              49  Electric, gas, and sanitary
                                                                              services.
                                                        622              80  Health services.
                                                        611              82  Educational services.
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    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be subject to the final 
rule amendments. To determine whether your facility may be subject to 
the final rule 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 final rule 
amendments to a particular entity, contact the person listed in the 
preceding FOR FURTHER INFORMATION CONTACT section.

[[Page 9867]]

    Worldwide Web (WWW). In addition to being available in the docket, 
an electronic copy of today's action is available on the WWW through 
the Technology Transfer Network (TTN). Following signature, EPA has 
posted a copy of today's action on the TTN's policy and guidance page 
for newly proposed or promulgated rules at http://www.epa.gov/ttn. The 

TTN provides information and technology exchange in various areas of 
air pollution control.
    Judicial Review. Under section 307(b)(1) of the Clean Air Act 
(CAA), judicial review of the final rule is available only by filing a 
petition for review in the U.S. Court of Appeals for the District of 
Columbia by April 28, 2006. Under section 307(d)(7)(B) of the CAA, only 
an objection to the final rule that was raised with reasonable 
specificity during the period for public comment can be raised during 
judicial review. Moreover, under section 307(b)(2) of the CAA, the 
requirements established by today's final action may not be challenged 
separately in any civil or criminal proceedings brought by EPA to 
enforce these requirements.
    Section 307(d)(7)(B) of the CAA further provides that ``only an 
objection to a rule or procedure which was raised with reasonable 
specificity during the period for public comment (including any public 
hearing) may be raised during judicial review.'' This section also 
provides a mechanism for EPA to convene a proceeding for 
reconsideration, ``if the person raising an objection can demonstrate 
to EPA that it was impracticable to raise such objection within [the 
period for public comment] or if the grounds for such objection arose 
after the period for public comment (but within the time specified for 
judicial review) and if such objection is of central relevance to the 
outcome of the rule.'' Any person seeking to make such a demonstration 
to EPA should submit a Petition for Reconsideration to the Office of 
the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200 
Pennsylvania Ave., NW., Washington, DC 20460, with a copy to both the 
person(s) listed in the FOR FURTHER INFORMATION CONTACT section, and 
the Director of the Air and Radiation Law Office, Office of General 
Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave, NW., 
Washington, DC 20004.
    Outline. The following outline is provided to aid in locating 
information in this preamble.

I. Summary of the Final Rule.
    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 steam generating units (40 CFR part 60, subpart Dc)?
II. Background Information
    A. What is the statutory authority for the final rule?
    B. What is the regulatory authority for the final rule?
III. Responses to Public Comments
    A. Electric Utility Steam Generating Units (40 CFR Part 60, 
Subpart Da)
    B. Industrial-Commercial-Institutional and Small Industrial-
Commercial-Institutional Steam Generating Units (40 CFR Part 60, 
Subparts Db and Dc)
IV. Impacts of the Final Rules
    A. What are the impacts for electric utility steam generating 
units (40 CFR part 60, subpart Da)?
    B. What are the impacts for industrial-commercial-institutional 
boilers (40 CFR part 60, subparts Db and Dc)?
    C. What are the economic impacts?
    D. What are the social costs and benefits?
V. 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
    J. Congressional Review Act

I. Summary of Final Rule

    The final rule amends the emission limits for SO2, 
NOX, and PM for subpart Da, 40 CFR part 60 (electric utility 
steam generating units) the SO2 and PM emission limits for 
subpart Db, 40 CFR part 60 (industrial-commercial-institutional steam 
generating units), and the SO2 and PM emission limits for 
subpart Dc, 40 CFR part 60 (small industrial-commercial-institutional 
steam generating units). With one exception, only those units that 
begin construction, modification, or reconstruction after February 28, 
2005, will be affected by the final rule. The exception is that the 
SO2 standard for industrial-commercial-institutional units 
presently subject to the NSPS has been amended to reflect the 
difficulty of units burning fuels with inherently low sulfur emissions 
from consistently achieving 90 percent reduction. Compliance with the 
emission limits of the final rule will be determined using similar 
testing, monitoring, and other compliance provisions set forth in the 
existing standards.
    In addition to the emissions limits contained in the final rule, we 
also are including several technical clarifications and corrections to 
existing provisions of the existing amendments, as explained below. We 
included 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 and combined 
heat and power combustion turbines burning less than 75 percent (by 
heat input) synthetic-coal gas are not 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 of 40 CFR part 60 will apply to 
combined cycle and combined heat and power combustion turbines and the 
associated heat recovery units that burn 75 percent or more (by heat 
input) synthetic-coal gas (e.g., integrated coal gasification combine 
cycle power plants) and that meet the applicability criteria of the 
final rule amendments, respectively.
    We also made amendments to the definitions for boiler operating 
day, cogeneration, coal, gross output, and petroleum. The purpose of 
the final rule 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 clarified the definition of an ``electric utility steam 
generating unit'' as applied to cogeneration units.

A. What are the requirements for new electric utility steam generating 
units (40 CFR part 60, subpart Da)?

    The PM emission limit for new and reconstructed electric utility 
steam generating units is 6.4 nanograms per joule (ng/J) (0.015 pound 
per million British thermal units (lb/MMBtu)) heat input or 99.9 
percent reduction regardless of the type of fuel burned. The PM 
emission limit for modified electric utility steam generating units is 
6.4 ng/J (0.015 lb/MMBtu) heat input or 99.8 percent reduction 
regardless of the type of fuel burned. Compliance with this emission 
limit can be determined using similar testing, monitoring, and other 
compliance provisions for PM standards set forth in the existing rule. 
While not required, PM CEMS may be used as an alternative method to 
demonstrate continuous compliance

[[Page 9868]]

and as an alternative to opacity and parameter monitoring requirements.
    The SO2 emission limit for new electric utility steam 
generating units is 180 ng/J (1.4 pound per megawatt hour (lb/MWh)) 
gross energy output or 95 percent reduction regardless of the type of 
fuel burned with one exception. The SO2 emission limit for 
new electric utility steam generating units that burn over 75 percent 
coal refuse (by heat input) is 180 ng/J (1.4 lb/MWh) gross energy 
output or 94 percent reduction. The SO2 emission limit for 
reconstructed and modified electric utility steam generating units 
burning any fuel except over 75 percent coal refuse (by heat input) is 
65 ng/J (0.15 lb/MMBtu) heat input or 95 percent reduction and 65 ng/J 
(0.15 lb/MMBtu) heat input or 90 percent reduction, respectively. The 
SO2 emission limit for reconstructed and modified electric 
utility steam generating units burning over 75 percent coal refuse (by 
heat input) is 65 ng/J (0.15 lb/MMBtu) or 94 percent reduction and 65 
ng/J (0.15 lb/MMBtu) or 90 percent reduction, respectively. Compliance 
with the SO2 emission limit is 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 NOX emission limit for new 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 is determined on a 30-day rolling average 
basis using similar 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. 
The NOX limit for reconstructed and modified electric 
utility steam generating units is 47 ng/J (0.11 lb/MMBtu) heat input 
and 65 ng/J (0.15 lb/MMBtu) heat input, respectively.

B. What are the requirements for industrial-commercial-institutional 
steam generating units (40 CFR part 60, subpart Db)?

    The PM emission limit for new and reconstructed industrial-
commercial-institutional steam generating units is 13 ng/J (0.03 lb/
MMBtu) for units that burn coal, oil, gas, wood, or a mixture of these 
fuels with other fuels. The PM emission limit for modified industrial-
commercial-institutional steam generating units is 13 ng/J (0.03 lb/
MMBtu) heat input or 99.8 percent reduction [with a maximum emission 
limit of 22 ng/J (0.051 lb/MMBtu) heat input] for units that burn coal, 
oil, gas, wood, or a mixture of these fuels with other fuels with two 
exceptions. The standard for modified wood-fired units with a maximum 
heat input less than or equal to 250 MMBtu/h is 43 ng/J (0.10 lb/MMBtu) 
heat input and 37 ng/J (0.085 lb/MMBtu) heat input for larger modified 
wood-fired boilers. While not required, PM CEMS may be used as an 
alternative method to demonstrate continuous compliance and as an 
alternative to opacity monitoring requirements.
    Units burning only oil, that contains no more than 0.3 weight 
percent sulfur, or liquid or gaseous fuels with a potential sulfur 
dioxide emission rate equal to or less than 140 ng/J (0.32 lb/MMBtu) 
heat input, may demonstrate compliance with the PM standard by 
maintaining certification of the fuels burned. Such units are not 
required to conduct PM compliance tests, conduct continuous monitoring, 
or comply with any other recordkeeping or reporting requirements unless 
the boiler changes the fuel burned to something other than the 
certified fuels.
    The SO2 emission limit for new and reconstructed 
industrial-commercial-institutional steam generating units is 87 ng/J 
(0.20 lb/MMBtu) heat input, or 92 percent reduction with a maximum 
emission rate of 520 ng/J (1.2 lb/MMBtu). Compliance with the 
SO2 emission limits is determined following similar 
procedures as in the existing NSPS.
    Units burning only oil that contains no more than 0.3 weight 
percent sulfur or any individual fuel that, when combusted without 
SO2 emission control, have an SO2 emission rate 
equal to or less than 140 ng/J (0.32 lb/MMBtu) heat input are exempt 
from other SO2 emission limits and may demonstrate 
compliance with the SO2 standard by maintaining 
certification of the fuels burned. Such units are not required to 
conduct SO2 compliance tests, conduct continuous monitoring, 
or comply with any other recordkeeping or reporting requirements unless 
the boiler changes the fuel burned to something other than the 
certified fuels.
    An alternate numerical SO2 limit of 87 ng/J (0.20 lb/
MMBtu) heat input has been added both for units presently subject to 
the NSPS and for modified units. The alternative limit has been made 
available to units presently subject to the NSPS as well as modified 
units in recognition of the technical difficulties of facilities firing 
inherently low sulfur fuels to achieve 90 percent reduction.

C. What are the requirements for small industrial-commercial-
institutional steam generating units (40 CFR part 60, subpart Dc)?

    The PM emission limit for new and reconstructed small industrial-
commercial-institutional steam generating units is 13 ng/J (0.03 lb/
MMBtu) heat input for units that burn coal, oil, gas, wood, or a 
mixture of these fuels with other fuels. The PM emission limit for 
modified industrial-commercial-institutional steam generating units is 
13 ng/J (0.03 lb/MMBtu) heat input or 99.8 percent reduction for units 
that burn coal, oil, gas, wood, or a mixture of these fuels with other 
fuels with one exception. The standard for modified wood-fired 
industrial-commercial-institutional steam generating units is 43 ng/J 
(0.10 lb/MMBtu) heat input. These limits apply to units between 8.7 MW 
and 29 MW (30 to 100 MMBtu/h) heat input. While not required, PM CEMS 
may be used as an alternate method to demonstrate continuous compliance 
and as an alternative to opacity monitoring.
    Units burning only oil that contains no more than 0.5 weight 
percent sulfur or liquid or gaseous fuels that, when combusted without 
SO2 emission control, have a SO2 emission rate 
equal to or less than 230 ng/J (0.54 lb/MMBtu) heat input, may 
demonstrate compliance with the PM standard by maintaining 
certification of the fuels burned. Such units are not required to 
conduct PM compliance tests, conduct continuous monitoring, or any 
other recordkeeping or reporting requirements unless the boiler changes 
the fuel burned to something other than the certified fuels.

II. Background Information

A. What is the statutory authority for the final rule?

    New source performance standards 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).

[[Page 9869]]

    Section 111(b)(1)(B) of the CAA requires EPA to periodically review 
and revise the standards of performance, as necessary, to reflect 
improvements in methods for reducing emissions.

B. What is the regulatory authority for the final rule?

    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 MMBtu/h) 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, the use of output-based emission limits was 
incorporated.
    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/h). 
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/h) but less than 29 MW (100 MMBtu/h). Those standards apply to 
units that commenced construction, reconstruction, or modification 
after June 9, 1989.

III. Responses to Public Comments

    The proposed rule was published February 28, 2005 (70 FR 9706).

A. Electric Utility Steam Generating Units (40 CFR Part 60, Subpart Da)

Greenhouse Gases
    Comment: One group of commenters state that CAA section 111 
requires EPA to set standards of performance for each pollutant emitted 
by a source category that causes, or contributes significantly to air 
pollution which may reasonably be anticipated to endanger public health 
or welfare. The commenters presented an argument to support their 
conclusion that carbon dioxide (CO2) and other greenhouse 
gases emitted by steam generating units are ``reasonably anticipated to 
endanger public health or welfare.'' Thus, EPA must set NSPS for 
greenhouse gases emitted from steam generating units.
    One commenter states that the electricity sector includes the 
nation's largest sources of CO2 emissions, and it is 
essential that EPA utilize its authority to limit CO2 
emissions under CAA section 111. The commenter states that, in the 
preamble, EPA alludes to the importance of controlling greenhouse 
gases, and that EPA revised its earlier position that it did have 
authority to regulate CO2; the commenter notes that this 
position is currently under judicial review. The commenter summarizes 
the public health dangers from rising CO2 levels and 
provides supporting attachments to its submittal. The commenter states 
that technologies, e.g., integrated gasification combine cycle (IGCC) 
technology and others, are available to the electric utility industry 
to reduce CO2 emissions that were not available in 1979 when 
the power plant NSPS were promulgated. The commenter attached 
supporting information on the available technology for lowering 
CO2 emissions. For existing sources, the commenter 
recommends that EPA require States to implement standards of 
performance for CO2 from existing sources. According to the 
commenter, CAA section 111(d) provides that EPA require States to 
implement standards of performance for existing sources when the 
pollutant is not regulated as a criteria pollutant. A program of 
trading CO2 emission credits is an effective way of 
regulating CO2 emissions from existing sources.
    One commenter recommends that EPA set CO2 emission 
limits as minimum thermal efficiency levels for boilers.
    Response: EPA's statutory authority for establishing NSPS to 
control air pollutants from stationary sources is under CAA section 
111. EPA has concluded that it does not presently have the authority to 
set NSPS to regulate CO2 or other greenhouse gases that 
contribute to global climate change.

Selection of NOX Emission Level

    Comment: One group of commenters state that to meet the 
requirements of CAA section 111, EPA must establish a NOX 
limit of no more than 0.5 lb/MWh for electric utility steam generating 
units. The commenters present information and data references to 
support their selection of a NOX emission level for the 
NSPS.
    One commenter states that a lower NOX emission standard 
of 0.7 or 0.8 lb/MWh is justified based on existing demonstrated 
technology and is consistent with the mandate in section 111 of the 
CAA. The commenter cites two fluidized bed boilers that began operating 
in the late 1980s and have been retrofitted with selective non-
catalytic reduction (SNCR) and have actual NOX emission 
rates between 0.12 and 0.13 lb/MMBtu.
    One commenter states that the standards for NOX are 
insufficiently stringent and do no reflect the best system of emission 
reduction as required by CAA section 111. The commenter provides the 
following supporting rationale for their view: The 1.0 lb/MWh standard 
is based on an input-based level of 0.11 lb/MMBtu, which is well above 
the levels being achieved with recent selective catalytic reduction 
(SCR) installations. The commenter attached 2003 data showing at least 
62 coal-fired plant units achieving a rate of 0.100 lb/MMBtu or below 
and 37 units emitted at a rate at or below 0.080 lb/MMBtu. New plants 
should be able to do better. EPA acknowledges that SCR can reduce 
NOX emissions by at least 90 percent. Because most existing 
facilities subject to the final rule are meeting rates of 0.30-0.60 lb/
MMBtu without SCR, units with SCR should readily achieve these levels. 
Even though EPA recognizes that SCR is BDT, it is proposing a less 
stringent standard based on fluidized beds and advanced combustion 
controls as an alternative to SCR or SNCR. This contravenes section 
111. EPA uses efficiency data for existing plants rather than higher 
efficiency levels achievable by new plants using either SCR or IGCC 
technology. A standard closer to the lower end of the range being 
considered is appropriate.

[[Page 9870]]

    One commenter states that new coal-fired units can achieve 
NOX emission limits of less than 0.500 lb/MWh through the 
implementation of low NOX burners and SCR technologies.
    One commenter reviewed recent BACT determinations in new source 
permits for electric utility steam-generating units of more than 250 
MMBtu/h (combusting bituminous, sub-bituminous, anthracite and lignite 
coal) from EPA's Clean Air Technology Center RACT/BACT/LAER 
Clearinghouse (RBLC) and examined the five most recent permitting 
decisions. The commenter included RBLC data showing that the permitted 
NOX emission limits for all five were 0.07 or 0.08 lb/MMBtu. 
The commenter states that, as reflected in the RBLC, a limit of 0.08 
lb/MMBtu is achievable using SCR and low NOX burners, and 
notes that EPA cites SCR as the basis for its proposed limit of 1.0 lb/
MWh (equivalent to 0.11 lb/MMBtu). The commenter recommends an output-
based standard equivalent to a heat-input based standard between 0.07 
and 0.08 lb/MMBtu.
    Response: EPA disagrees that the amended NSPS are inappropriate. 
EPA acknowledges that boiler types and control configurations are 
technically capable of achieving lower NOX emissions. EPA 
has concluded that with advanced combustion controls, coal-fired 
electric utility steam-generating units are able to achieve a 
NOX emissions rate of 1.0 lb/MWh (0.11 lb/MMBtu). The 
incremental cost of requiring SCR for reduction to 0.7 lb/MWh (0.08 lb/
MMBtu) is approximately $5,000 per ton. The final NOX 
standard is based on the best demonstrated technology taking into 
account costs, other environmental impacts, and additional energy 
requirements. Requiring SCR in addition to advanced combustion controls 
not only increases costs and decreases the net efficiency of the unit, 
but leads to ammonia emissions and catalyst disposal concerns. States 
and BACT permitting process are still capable of requiring additional 
controls as appropriate.
NOX Control for Lignite-Fired Steam-Generating Units
    Comment: Several commenters disagree with EPA's assessment of the 
feasibility of meeting the proposed NOX limit for lignite-
fired boilers. The commenters disagree with EPA's assessment that units 
burning lignite can meet the proposed NOX limit with either 
SCR or fluidized bed combustors and SNCR because EPA is specifying a 
boiler design that has never been built larger than 300 MW and is 
generally no larger than 100 MW. According to the commenter, this 
violates CAA section 111(b)(5) which prohibits setting a standard based 
upon a particular technology. One commenter states that information was 
provided to EPA prior to proposal suggesting that pore pluggage of SCR 
catalysts makes the proposed limit of 1.0 lb/MWh unachievable at 
lignite units. According to the commenter, there were no commercial 
applications of SCR (retrofit or new unit applications) for either 
northern or southern lignite. One commenter cites published research 
showing SCR technology ineffective for NOX reduction from 
lignite-fired steam-generating units and states that it is unlikely 
that any new pulverized coal units using Fort Union lignite would 
install SCR technology to reduce NOX emissions. The 
commenter also states that combustion controls, the only effective 
means to reduce NOX emissions at some lignite-fired units, 
have been problematic for Fort Union lignite. The commenter recommends 
retaining the current NSPS of 1.6 lb/MWh for units burning Fort Union 
lignite.
    Response: EPA disagrees that lignite-fired steam-generating units 
would not be able to achieve the amended NSPS. While there are no 
existing lignite-fired electric utility steam-generating units with SCR 
in the United States, there is considerable experience in the industry 
to show that use of SCR on lignite is technically feasible. EPA has 
concluded that the primary reason that no pulverized lignite-fired 
units are equipped with SCR is because no new pulverized lignite unit 
has been built in the United States since 1986.
    The Electric Power Research Institute testing of SCR catalyst in a 
slipstream at the Martin Lake Power plant showed acceptable results 
from Gulf Coast lignite. In addition, two recent permit applications 
for pulverized lignite-fired utility units in Texas (Twin Oaks 3 and 
Oak Grove facilities) propose to use SCR to control NOX 
emissions to 0.07 and 0.10 lb/MMBtu, respectively. Finally, technology 
suppliers report that SCR has been successfully used on lignite and 
brown coal boilers in Europe. EPA has concluded that SCR can be used on 
lignite boilers in the United States and catalyst suppliers have 
indicated that they will offer performance guarantees on these 
applications.
    Pore plugging and binding of a catalyst is a common problem 
experienced by pilot test facilities. In full scale installations, this 
concern is addressed during the SCR design stage. The methods used to 
avoid this problem include duct design to promote ash fallout prior to 
the SCR, catalyst reactor design to avoid ash buildup, and on-line 
cleaning methods (soot blowers and sonic horns).
    In addition, the use of SCR is not required to comply with the 
amended NOX standard. The existing Big Brown facility in 
Texas burns pulverized Gulf Coast lignite and is able to achieve 0.15 
lb NOX/MMBtu with combustion controls alone. EPA has 
concluded that new lignite-fired units would either be able to achieve 
the amended standards without the use of any backend controls or could 
use SNCR to comply. Existing units at 0.15 lb/MMBtu would only need 30 
percent NOX reduction to comply with the amended 
NOX standard. This level of control has been demonstrated 
for existing pulverized coal (PC) units retrofit with SNCR, and new 
units could achieve even better results.
    Fluidized bed combustion and gasification are also options for new 
lignite units. The proposed permits for the Westmoreland and South 
Heart facilities in North Dakota both propose to burn Fort Union 
lignite in fluidized beds and use SNCR to achieve a NOX 
emissions limit of 0.09 lb/MMBtu. With regard to size, Foster Wheeler 
recently designed a 460 MW supercritical fluidized bed.
Selection of SO2 Emission Limit
    Comment: One group of commenters state that EPA's proposed 
SO2 standard for electric utility steam-generating units 
violates CAA section 111 because it does not reflect BDT for this 
source category. EPA also did not consider foreign experience or 
advanced scrubber designs, which indicate lower SO2 limits 
have been achieved and are achievable. The processes that have 
demonstrated greater than 98 percent SO2 removal and for 
which vendors offer guarantees greater than 98 percent are the 
magnesium-enhanced lime (``MEL'') flue gas desulfurization (FGD) 
process, the Chiyoda CT-121 bubbling jet reactor, and circulating 
fluidized bed scrubbers. Further, design enhancements and additives are 
available that can increase SO2 removal efficiencies above 
98 percent for other technologies within this general class. Also, EPA 
did not consider the use of coal washing in its determination.
    Response: EPA has concluded that 98 percent control is possible 
with certain control and boiler configurations under ideal conditions. 
The amended SO2 standard is based on a 30-day average that 
includes the variability that occurs from non-ideal operating 
conditions. The best long-term SO2 control performance data 
that EPA has available

[[Page 9871]]

are for the Harrison, Conemaugh, Northside, Clover, and similar 
facilities. The amended standards are based on operational data from 
these facilities. EPA has concluded that this level of control is 
achievable for a broad range of coal and boiler types.
    Comment: One group of commenters state that to meet the 
requirements of CAA section 111, EPA must establish a SO2 
limit of no more than 0.9 lb/MWh for all utility steam-generating 
units. Alternatively, if EPA finds that this standard would be cost-
prohibitive for high sulfur coal, then it should either set emissions 
limits on a sliding scale that reflects BDT for coals of increasing 
sulfur content, or establish both stringent emissions limits and 
stringent percentage reduction requirements that would apply 
simultaneously. The commenters' review of proposed and final emission 
limits in recent permits and permit applications for 32 recent coal-
fired steam-generating unit projects found 9 units with emissions 
limits of 0.10 lb/MMBtu or lower (0.95 lb/MWh or lower, assuming 36 
percent efficiency) and 22 units with emission limits of 0.13 lb/MMBtu 
or lower (1.2 lb/MWh or lower).
    One commenter states that the standard for SO2 is 
insufficiently stringent and does not reflect the best system of 
emission reduction as required by CAA section 111. The commenter 
provides the following supporting rationale:
     About 70 percent of coals in use can meet the proposed 
limit with add-on controls. The data before EPA supports a limit at the 
low end of the range being considered by EPA (0.90-2.0 lb/MWh) rather 
than the proposed level (2.0 lb/MWh), which is at the top of the range.
     All coals currently in use can meet a more stringent 
standard, e.g., 88 percent of coals currently in use can meet 1.1 lb/
MWh without pretreatment and using wet lime FGD that consistently 
achieves a 97 percent reduction; EPA has determined that reductions 
greater than 98 percent are demonstrated.
     For high sulfur coals, other technologies are available, 
e.g., IGCC technology which is capable of reductions of over 99 
percent. The highest sulfur coals (uncontrolled level of 7.92 lb/MMBtu) 
can meet 1.1 lb/MWh using technologies that reduce sulfur levels by 99 
percent. Other options for meeting more stringent standards include 
coal washing and blending with low sulfur coals.
     Actual 2003 emissions data show 25 plants with scrubbers 
achieving emissions at or below 0.10 lb/MMBtu (data attached to 
commenter's submittal). EPA's BACT/LAER clearinghouse establishes 
permitted levels for new scrubbers below the proposed standard and as 
low as 0.06 lb/MMBtu; IGCC units show even lower permitted levels, 0.03 
and 0.032 lb/MMBtu.
     Vendors of scrubber report removal efficiencies of 99.5 
percent of sulfur from high sulfur coal (as high as 4 percent) 
achieving SO2 emission rates of 0.04 lb/MMBtu. The commenter 
attached a supporting report by a vendor of scrubber equipment.
     New Source Review (NSR) enforcement settlements reflect 
better emission rates than 0.21 lb/MMBtu even at existing plants. EPA 
routinely obtains commitments for FGD retrofits to meet rates of 0.100 
to 0.130 lb/MMBtu. The commenter attached supporting consent decrees.
     EPA's proposed standards rely on an estimate that new 
plants will operate at a 36 percent gross efficiency even though the 
top 10 percent of existing units operate at 38 percent. This is 
unreasonable given that the standards will govern new PC plants, with 
new supercritical plants able to achieve a net efficiency of 45 percent 
and a gross efficiency of 40 percent.
    One commenter states that new coal-fired units can achieve 
SO2 emission limits of 0.500 to 1.5 lb/MWh depending on 
sulfur content. The commenter supports lower SO2 limits for 
lower sulfur coal and suggests that this can be done by maintaining a 
percent reduction requirement or setting a range of SO2 
limits based on sulfur content of coal. The commenter recommends that 
where a percent reduction limit is used, it should be in addition to 
the emission rate limit.
    One commenter recommends an output-based limit equivalent to a 
heat-input based limit of 0.10 lb/MMBtu. Based on a survey of EPA's 
RBLC for recent permitting decisions, permitted SO2 levels 
of 0.022 to 0.12 lb/MMBtu, are common State requirements. EPA's 
argument for a higher limit to account for the highest-sulfur coal is 
flawed because industry can use lower sulfur coal or use technologies 
to reduce SO2 emissions beyond the proposed level.
    Response: EPA acknowledges that certain boiler and coal 
configurations are technically capable of achieving SO2 
emissions rates of 1.0 lb/MWh. The NSPS are based on limits that can be 
achieved on a consistent basis for a broad range of boiler and coal 
types. High sulfur coals are an important part of the United States 
energy resources, and spray dryers for SO2 control are 
important in locations with limited water resources. EPA has concluded 
that it is vital that the amended NSPS preserve the use of both high 
sulfur coals and spray dryers. Therefore, EPA is amending the 
SO2 standard to allow units greater flexibility in complying 
with the final SO2 standard. The amended SO2 
standard is either 1.4 lb/MWh or 95 percent reduction on a 30-day 
rolling average. The numerical limit is aggressive, but preserves the 
ability of approximately half the coals presently used in the United 
States to use spray dryers. The percent maximum reduction requirement 
is similarly aggressive, but preserves the ability of units to burn 
high sulfur coals. Based on the sulfur content of coals presently being 
burned in the United States, EPA has concluded that the majority of new 
units will comply with the 1.4 lb/MWh standard, but has provided the 
maximum percent reduction requirement to address the concerns of users 
of high sulfur coals. The BACT permitting process and states 
requirements are able to require additional controls as appropriate.
    Comment: One commenter states that many scrubbers used for high 
sulfur coals--3 to 4 percent sulfur--will be unable to meet the 
proposed SO2 limit of 2.0 lb/MWh on a consistent basis. 
According to the commenter, EPA has based their decision on a single, 
high performance magnesium-enhanced lime scrubber, i.e., the Harrison 
facility in Pennsylvania. The commenter states that the specialty agent 
used at the unit may not be broadly available and brings into question 
whether the SO2 levels being attained at this plant can be 
sustained long term. The commenter also states that EPA's use of a 
scrubber at a single facility as the basis for the SO2 limit 
is in conflict with CAA section 111(b)(5), which prohibits setting a 
standard based upon a particular technology.
    The commenter continues by stating that there is considerable 
uncertainty that the high removal efficiency that would be required for 
high sulfur coals can consistently and broadly be achieved. According 
to the commenter, coals with sulfur content exceeding 2.5 percent would 
require removal efficiencies of up to 98 percent; for these coals, wet 
scrubbers are the sole option and uncertainties in meeting the NSPS may 
dissuade some from using such coals.
    Response: The final rule amendments allow units to either comply 
with an output-based limit of 1.4 lb/MWh or demonstrate 95 percent 
reduction. The maximum percent reduction requirement is achievable for 
multiple boiler and control configurations and addresses concerns of 
the use of high sulfur fuels.

[[Page 9872]]

Particulate Matter Emission Limit
    Comment: One commenter states that fabric filters, the technology 
on which the proposed PM emission standard is based, is problematic 
with coals whose sulfur content exceeds 1.5 percent. With only 134 of 
1,250 U.S. coal-fired power plants using fabric filters, the commenter 
notes that with the exception of a limited number of applications on 
small atypical boilers, there are no fabric filters in operation on 
plants firing sulfur greater than 2.0 percent by weight. The commenter 
cites an example of a plant that encountered problems after installing 
a fabric filter on a unit burning medium-or high-sulfur coal. For this 
reason, the commenter states that EPA's proposed PM standard is neither 
achievable nor adequately demonstrated for all coals.
    Response: In general, EPA disagrees with the comment that the use 
of fabric filters to control PM emissions is problematic for electric 
utility steam generating units firing coals with sulfur contents 
exceeding 1.5 percent. The example cited by the commenter is for a 
retrofit application of a fabric filter at an existing facility for 
which the temperature of the flue gas in the fabric filter unit was not 
maintained above the acid dew point. Consequently, acid mist formed in 
the flue gas, condensed on the bags and internal components of the 
unit, and adversely impacted the performance of the control device. 
Based on discussions with fabric filter equipment suppliers, EPA has 
concluded that a similar problem should not occur in fabric filters 
installed on new and reconstructed facilities because of the capability 
at these sites to incorporate design options that will maintain the 
temperature of the flue gas passing through the fabric filter at levels 
above the acid dew point of the flue gas. These options include use of 
high temperature bags and injection of hydrated lime to lower the acid 
dew point of the flue gas. The Department of Energy sponsored two 
demonstration projects (SNOX Flue Gas Cleaning Demonstration Project 
(SNOX) and SOX-NOX-ROX-Box Flue Gas 
Cleanup Demonstration Project (SNRB) projects) that successfully used 
fabric filters for PM control for electric utility steam generating 
units burning high sulfur coal, potential SO2 emissions of 5 
and 6 lb/MMBtu, respectively. In addition, two recent permit 
applications propose to use fabric filters for PM control while burning 
relatively high sulfur coals. The Longview power plant in West Virginia 
is proposing to burn 2.5 percent sulfur coal, and the Elm Road plant is 
proposing to burn coal with potential SO2 emissions of 4 lb/
MMBtu.
    EPA recognizes that in certain site-specific situations where an 
existing electric utility steam generating unit becomes subject to the 
NSPS because of modifications to the unit, replacement of an 
electrostatic precipitator (ESP) with a fabric filter could be 
problematic. Not all locations may be able to cost-effectively maintain 
the temperature of the flue gas in a fabric filter above the acid dew 
point of the flue gas because of existing site conditions and space 
constraints. Therefore, EPA decided it is appropriate to establish a 
separate PM standard for modified sources subject to subpart Da, 40 CFR 
part 60. Owners and operators of modified electric utility steam 
generating units subject to the NSPS are given the option of meeting 
either a 0.015 lb/MMBtu or 99.8 percent reduction standard. ESPs can be 
modified to cost-effectively achieve this level of control.
    Comment: One commenter takes issue with EPA's proposed input-based 
standard for PM emissions. According to the commenter, although EPA 
determined that ESPs and fabric filters are the best demonstrated 
technology for controlling filterable particulate matter, EPA's 
justification for the revised PM limit is based on three plants where 
fabric filtration is used. The commenter also states that of the three 
plants, two use fluidized bed boilers, which use limestone as an active 
bed material, significantly altering the nature of the PM generated for 
collection. The commenter states that the record does not support the 
proposed NSPS for PM for ESPs or that fluidized bed combustors are 
appropriate units on which to base PM standards for pulverized coal 
steam generating units, which are projected to make up the majority of 
new units.
    Response: EPA has gathered additional stack test data that 
indicates an ESP could be used by the majority of coal types to comply 
with the final rule amendments. Based on ESP cost models, they are 
often less expensive than fabric filters for high sulfur applications. 
Additional information is available in the PM control cost memorandum.
    Comment: One group of commenters state that the proposed opacity 
limit does not reflect BDT because the proposed rule retains the 
existing opacity limit of 20 percent. The commenters state that this 
limit is over 20 years old, and is not based on the performance of 
modern baghouse control systems. Because EPA has acknowledged in the 
proposed rule that the former 0.03 lb/MMBtu PM limit should at least be 
halved to 0.015 lb/MMBtu, there should be a proportionate halving of 
the opacity limit, from 20 percent to 10 percent. Ten percent opacity 
can be easily and continuously attained by subpart Da, 40 CFR part 60, 
facilities using appropriate control technology. There are existing 
power plants around the country with BACT limits of 10 percent for 
opacity, including the Sevier Power Company--Sigurd plant in Utah, 
Intermountain Power in Utah, and Plum Point Energy in Arkansas.
    Response: Since opacity is used as an indication on PM emissions, 
EPA has provided sources with two options to demonstrate continuous 
compliance with the amended PM standard. Sources may elect to install 
and operate PM CEMS and demonstrate compliance each boiler operating 
day. For these units, opacity monitoring shall no longer be required. 
Units that do not install PM CEMS shall perform stack tests to 
demonstrate compliance and shall still be subject to the existing 6-
minute opacity limit. In addition, sources shall use bag leak detectors 
or monitor ESP parameters in addition to developing a site-specific 
opacity trigger level that is based on the opacity during the stack 
test. Sources that deviate from this opacity or other parameter are 
required to perform a stack test within 60 days of the deviation. Stack 
opacity characteristics are different for fabric filters and ESP. 
Therefore, EPA has concluded that a site-specific opacity trigger is 
the best approach to monitor continuous compliance.

B. Industrial-Commercial-Institutional and Small Industrial-Commercial-
Institutional Steam Generating Units (40 CFR Part 60, Subparts Db and 
Dc)

    Comment: Several commenters opposed both the proposed single 
SO2 limit of 0.24 lb/MMBtu heat input and the limit of 
either 0.15 lb/MMBtu heat input or 95 percent reduction for a variety 
of reasons. Several commenters believed that these approaches would 
discourage the use of high sulfur coals found in the Midwest and would 
be difficult to meet consistently for circulating fluidized bed boilers 
and boilers burning low sulfur coal. They also stated that industrial 
boilers cannot routinely achieve high percent reductions of 95 percent 
or more, as would be required to meet these standards, because of 
variations in coal quality and operational variations due to 
fluctuations in steam demand. Also, meeting 95 percent reduction would 
not be feasible for existing units that are modified. Three of the 
commenters recommended adopting the same SO2

[[Page 9873]]

standard as subpart Da, 40 CFR part 60 (90 percent reduction with a 70 
percent reduction for units that demonstrate emissions below 0.20 lb/
MMBtu heat input). Two commenters recommended retaining the current 90 
percent SO2 reduction requirement with an alternative 
emission limit of 0.24 lb/MMBtu heat input. One commenter supported 
EPA's decision that the current SO2 emission limits in 
subparts Db and Dc of 40 CFR part 60 should not be amended because 
option 1 and 2 would impose unacceptable compliance costs and are not 
warranted. One commenter also opposed reducing the SO2 limit 
for units with heat input capacities of 10-75 MMBtu/h.
    Several commenters maintained that the changes to the 
SO2 limit to remove the percent reduction requirement should 
apply to existing units as well as new units. Excluding existing units 
from the change would provide a disincentive to use low sulfur coal and 
would not provide relief for existing compliance problems. Many 
existing boilers were designed to achieve 90 percent reduction using 
high sulfur coals. An existing unit that wanted to switch to low sulfur 
coal would have difficulty in meeting a 90 percent requirement using 
existing control equipment. Also, circulating fluidized bed (CFB) 
boilers that use low sulfur coal have had difficulty in achieving a 90 
percent reduction consistently. The technical impossibility of 
measuring uncontrolled SO2 emissions at a CFB unit creates 
an inherent difficulty in adjusting limestone injection rate to 
accommodate short-term variations in coal sulfur content. One such unit 
that burns low sulfur coal has been cited for short-term violations of 
the NSPS even though average emissions were in the range of 0.13 lb/
MMBtu (0106).
    Response: After considering all the comments and additional 
information provided by commenters, we have decided to provide 
industrial units the following options. Units presently subject to the 
NSPS and modified units may reduce SO2 emissions by 90 
percent or meet an SO2 emission limit of 0.20 lb/MMBtu heat 
input. New and reconstructed units that become subject to the NSPS 
after February 28, 2005, may reduce SO2 emissions by 92 
percent or meet an SO2 emission limit of 0.20 lb/MMBtu heat 
input. This approach will be more stringent than the existing subpart 
Db, 40 CFR part 60, requirements, and at the same time allow units with 
difficulty in achieving high levels of SO2 control to 
overcome compliance demonstrations problems by burning low sulfur 
fuels.

IV. Impacts of the Final Rule?

A. What are the impacts for electric utility steam generating units (40 
CFR part 60, subpart Da)?

    We estimate that 5 new electric utility steam generating units will 
be installed in the United States over the next 5 years and affected by 
the final rule. All of these units will need to install add-on controls 
to meet the PM, SO2, and NOX limits required 
under the final rule. However, these boilers will already be required 
to install add-on PM, SO2, and NOX controls to 
meet the reduction requirements of the existing NSPS. Compared to the 
existing NSPS, the incremental PM, SO2, and NOX 
reductions resulting from the final rule will be 530 tons of PM, 8,400 
tons of SO2, and 1,400 tons of NOX. Using this 
comparison, the annualized cost of the final utility amendments are 
$4.4 million.
    Using this comparison, we expect the final rule to result in an 
increase in electrical supply generated by unaffected sources (e.g., 
existing electric utility steam generating units), we have concluded 
that this will not result in higher NOX, SO2, and 
PM emissions from these sources. Other emission control programs such 
as the Clean Air Interstate Rule (CAIR), the Clean Air Mercury Rule 
(CAMR), and PSD/NSR already promote or require emission controls that 
would effectively prevent emissions from increasing. All the emissions 
reductions estimates and assumptions have been documented in the docket 
to the final rule.
    A more accurate assessment of the emissions reductions and 
annualized costs of the final utility amendments include other 
regulatory programs that are presently requiring controls beyond what 
is required by the existing NSPS. The BACT permitting process requires 
new sources to install controls at or beyond what the final NSPS 
amendments require. In addition, the recently finalized CAIR and CAMR 
rules, along with the proposed revisions to ambient particulate matter 
standards, will push permits even lower. The amended NSPS reflect the 
levels of control presently being required by these other programs. 
Therefore, the actual environmental benefits and cost impacts of the 
final rule are essentially zero. A more detailed discussion of the cost 
and emissions impacts of the amended NSPS is available in the docket.

B. What are the impacts for industrial-commercial-institutional boilers 
(40 CFR part 60, subparts Db and Dc)?

    We estimate that approximately 186 new industrial-commercial-
institutional boilers will be installed in the United States over the 
next 5 years and affected by the final rule. All of these units will 
need to install add-on controls to meet the PM and SO2 
limits required under the final rule. However, these new boilers will 
already be required to install add-on PM and SO2 controls to 
meet the existing NSPS. The new source requirements under the maximum 
achievable control technology (MACT) program and PSD/NSR require new 
units presently to install controls beyond what is required by the 
existing NSPS.
    Wood-fired boilers are the only industrial sources that could 
potentially use the alternative compliance limit in the boiler MACT and 
would not be required to meet the new source MACT limit. We estimate 
that 17 new wood-fired boilers will be installed in the United States 
over the next 5 years and affected by the final rule. Using the 
existing NSPS as a baseline, the additional annualized costs are $2.2 
million, and the PM emissions reductions are 930 tons. EPA has 
concluded that new wood-fired units will not use the compliance 
alternatives available in the boiler MACT and that they will comply 
with the new source PM limit of 0.025 lb/MMBtu. Due to PSD/NSR and the 
limited applicability of the alternate compliance limit to new units, 
it will primarily only be used by existing wood-fired boilers. Thus, we 
concluded that the PM and SO2 reductions and costs resulting 
from the final rule will essentially be zero.

C. What are the economic impacts?

    Even though actual costs and benefits are essentially zero, EPA 
prepared an economic impact analysis comparing the existing NSPS with 
the amended NSPS to evaluate the impacts the final rule will have on 
electric utilities and consumers of goods and services produced by 
electric utilities. The analysis showed minimal changes in prices and 
output for products made by the industries affected by the final rule. 
The price increase for affected output is less than 0.003 percent, and 
the reduction in output is less than 0.003 percent for each affected 
industry. Estimates of impacts on fuel markets show price increases of 
less than 0.01 percent for petroleum products and natural gas, and 
price increases of 0.04 and 0.06 percent for base-load and peak-load 
electricity, respectively. The price

[[Page 9874]]

of coal is expected to decline by about 0.002 percent, and that is due 
to a small reduction in demand for this fuel type. Reductions in output 
are expected to be less than 0.02 percent for each energy type, 
including base-load and peak-load electricity.

D. What are the social costs and benefits?

    The social costs of the final rule are estimated at $0.4 million 
(2002 dollars). Social costs include the compliance costs, but also 
include those costs that reflect changes in the national economy due to 
changes in consumer and producer behavior in response to the compliance 
costs associated with a regulation. For the final rule, changes in 
energy use among both consumers and producers to reduce the impact of 
the regulatory requirements of the rule lead to the estimated social 
costs being less than the total annualized compliance cost estimate of 
$6.5 million. The primary reason for the lower social cost estimate is 
the increase in electricity supply generated by unaffected sources 
(e.g., existing electric utility steam generating units), which offsets 
mostly the impact of increased electricity prices to consumers. The 
social cost estimates discussed above do not account for any benefits 
from emission reductions associated with the final rule.

V. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), EPA 
must determine whether the regulatory action is ``significant'' and, 
therefore, subject to 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 rule 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, OMB has notified 
EPA that it considers the final rule amendments a ``significant 
regulatory action'' within the meaning of the Executive Order. EPA has 
submitted this action to OMB for review. Changes made in response to 
OMB suggestions or recommendations will be documented in the public 
record.

B. Paperwork Reduction Act

    The final rule amendments do not impose an information collection 
burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 
3501 et seq. The final rule 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 auby.susan@epa.gov, 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 
Procedure 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 final rules on small entities, small 
entity is defined as follows: (1) A small business that is an ultimate 
parent entity in the regulated industry that has a gross annual revenue 
less than $6.5 million (this varies by industry category, ranging up to 
$10.5 million for North American Industrial Classification System 
(NAICS) code 562213 (VSMWC)), based on Small Business Administration's 
size standards; (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; or (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 final rule 
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, 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 final 
rule amendments.
    We have determined for industrial-commercial steam generating 
units,

[[Page 9875]]

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 final rule 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/h; 
subpart Dc of 40 CFR part 60: 10-100 MMBtu/h), 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 refer to the economic impact analysis in the 
docket.
    Although the final rule amendments will not have a significant 
economic impact on a substantial number of small entities, EPA 
nonetheless has tried to reduce the impact of the final rule amendments 
on small entities. In the final rule 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.

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, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules 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 rule for which a written statement 
is needed, section 205 of the UMRA generally requires EPA 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 rule. The provisions of section 205 
do not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows EPA to adopt an alternative other than the least 
costly, most cost-effective, or least burdensome alternative if EPA 
publishes with the final rule an explanation why that alternative was 
not adopted.
    Before EPA establishes any regulatory requirements that may 
significantly or uniquely affect small governments, including Tribal 
governments, EPA 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 EPA's regulatory proposals with significant Federal 
intergovernmental mandates, and informing, educating, and advising 
small governments on compliance with the regulatory requirements.
    EPA has determined that the final rule amendments contain no 
Federal mandates 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 final rule amendments are not 
subject to the requirements of section 202 and 205 of the UMRA. In 
addition, we determined that the final rule 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 final rule 
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.''
    The final rule 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 final rule 
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 final rule amendments.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Executive Order 13175, (65 FR 67249, November 9, 2000), requires 
EPA 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 final rule 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 final rule 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 
rule that: (1) Is determined to be ``economically significant'' as 
defined under Executive Order 12866, and (2) concerns an environmental 
health or safety risk that EPA has reason to believe may have a 
disproportionate effect on children. If the regulatory action meets 
both criteria, EPA must evaluate the environmental health or safety 
effects of the planned rule on children, and explain why the planned 
regulation is preferable to other potentially effective and reasonably 
feasible alternatives EPA considered.
    EPA interprets Executive Order 13045 as applying only to those 
regulatory actions that are based on health or safety

[[Page 9876]]

risks, such that the analysis required under section 5-501 of the 
Executive Order has the potential to influence the regulation. The 
final rule amendments are not subject to Executive Order 13045 because 
they are based on technology performance and not on health and safety 
risks.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution or Use

    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 (NTTAA) of 1995 (Pub. L. No. 104-113; 15 U.S.C. 272 note) directs 
EPA to use voluntary consensus standards in their regulatory and 
procurement activities unless to do so would be inconsistent with 
applicable law or otherwise impractical. Voluntary consensus standards 
are technical standards (e.g., materials specifications, test methods, 
sampling procedures, business practices) developed or adopted by one or 
more voluntary consensus bodies. The NTTAA directs EPA to provide 
Congress, through annual reports to OMB, with explanations when an 
agency does not use available and applicable voluntary consensus 
standards.
    Today's 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 
today's action.

J. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. EPA will submit a report containing today's action and 
other required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the final rule in the Federal Register. A major rule 
cannot take effect until 60 days after it is published in the Federal 
Register. Today's action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). The final rule amendments will be effective February 27, 2006.

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, 2006.
Stephen L. Johnson,
Administrator.

0
For the reasons stated in the preamble, title 40, chapter I, part 60 of 
the Code of Federal Regulations is amended as follows:

PART 60--[AMENDED]

0
1. The authority citation for part 60 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.

Subpart Da--[Amended]

0
2. Section 60.40Da is amended by revising paragraph (b) to read as 
follows:

Sec.  60.40Da  Applicability and designation of affected facility.

* * * * *
    (b) Heat recovery steam generators that are associated with 
stationary combustion turbines burning fuels other than 75 percent (by 
heat input) or more synthetic-coal gas on a 12-month rolling average 
and that meet the applicability requirements of subpart KKKK of this 
part are not subject to this subpart. Heat recovery steam generators 
and the associated stationary combustion turbine(s) burning fuels 
containing 75 percent (by heat input) or more synthetic-coal gas on a 
12-month rolling average are subject to this part and are not subject 
to subpart KKKK of this part. 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/h) 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).
* * * * *

0
3. Section 60.41Da is amended by revising the definitions of ``Boiler 
operating day,'' ``Cogeneration,'' ``Electric utility steam-generating 
unit,'' and ``Gross output'' and by adding in alphabetical order the 
definitions of ``ISO conditions'' and ``Petroleum'' to read as follows:

Sec.  60.41Da  Definitions.

* * * * *
    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.
* * * * *
    Cogeneration, also known as ``combined heat and power,'' means a 
steam-generating unit that simultaneously produces both electric (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 12-month 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.
* * * * *
    Gross output means the gross useful work performed by the steam 
generated. For units generating only electricity, the gross useful work 
performed is the gross electrical output from the turbine/generator 
set. For cogeneration units, the gross useful work performed is the 
gross electrical output plus 75 percent of the useful thermal output 
measured relative to ISO conditions that is not used to generate 
additional electrical or mechanical output (i.e., steam delivered to an 
industrial process).
* * * * *
    ISO conditions means a temperature of 288 Kelvin, a relative 
humidity of 60

[[Page 9877]]

percent, and a pressure of 101.3 kilopascals.
* * * * *
    Petroleum means crude oil or petroleum or a fuel derived from crude 
oil or petroleum, including distillate, residual oil, and petroleum 
coke.
* * * * *

0
4. Section 60.42Da is amended by revising the introductory text in 
paragraph (a) and adding paragraphs (c) and (d) to read as follows:

Sec.  60.42Da  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 is commenced after February 28, 2005, 
except for modified affected facilities meeting the requirements of 
paragraph (d) of this section, any gases that contain particulate 
matter in excess of either:
    (1) 18 ng/J (0.14 lb/MWh) gross energy output; or
    (2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the 
combustion of solid, liquid, or gaseous fuel.
    (d) As an alternative to meeting the requirements of paragraph (c) 
of this section, the owner or operator of an affected facility for 
which construction, reconstruction, or modification commenced after 
February 28, 2005, may elect to meet the requirements of this 
paragraph. On and after the date on which the performance test required 
to be conducted under Sec.  60.8 is completed, the owner or operator 
subject to the provisions of this subpart shall not 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 particulate matter in excess of:
    (1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion 
of solid, liquid, or gaseous fuel, and
    (2) 0.1 percent of the combustion concentration determined 
according to the procedure in Sec.  60.48Da(o)(5) (99.9 percent 
reduction) for an affected facility for which construction or 
reconstruction commenced after February 28, 2005 when combusting solid 
fuel or solid-derived fuel, or
    (3) 0.2 percent of the combustion concentration determined 
according to the procedure in Sec.  60.48Da(o)(5) (99.8 percent 
reduction) for an affected facility for which modification commenced 
after February 28, 2005 when combusting solid fuel or solid-derived 
fuel.

0
5. Section 60.43Da is amended by revising the introductory text in 
paragraphs (a) and (b) and adding paragraphs (i), (j), and (k) to read 
as follows:

Sec.  60.43Da  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, 
except as provided for under paragraphs (j) or (k) of this section, any 
gases that contain sulfur dioxide in excess of the applicable emission 
limitation specified in paragraphs (i)(1) through (3) of this section.
    (1) For an affected facility for which construction commenced after 
February 28, 2005, any gases that contain sulfur dioxide in excess of 
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis, or
    (ii) 5 percent of the potential combustion concentration (95 
percent reduction) on a 30-day rolling average basis.
    (2) For an affected facility for which reconstruction commenced 
after February 28, 2005, any gases that contain sulfur dioxide in 
excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis,
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average 
basis, or
    (iii) 5 percent of the potential combustion concentration (95 
percent reduction) on a 30-day rolling average basis.
    (3) For an affected facility for which modification commenced after 
February 28, 2005, any gases that contain sulfur dioxide in excess of 
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis,
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average 
basis, or
    (iii) 10 percent of the potential combustion concentration (90 
percent reduction) on a 30-day rolling average basis.
    (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 for which construction, 
reconstruction, or modification commenced after February 28, 2005, and 
that burns 75 percent or more (by heat input) coal refuse on a 12-month 
rolling average basis, any gases that contain sulfur dioxide in excess 
of the applicable emission limitation specified in paragraphs (j)(1) 
through (3) of this section.
    (1) For an affected facility for which construction commenced after 
February 28, 2005, any gases that contain sulfur dioxide in excess of 
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis, or
    (ii) 6 percent of the potential combustion concentration (94 
percent reduction) on a 30-day rolling average basis.
    (2) For an affected facility for which reconstruction commenced 
after February 28, 2005, any gases that

[[Page 9878]]

contain sulfur dioxide in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis,
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average 
basis, or
    (iii) 6 percent of the potential combustion concentration (94 
percent reduction) on a 30-day rolling average basis.
    (3) For an affected facility for which modification commenced after 
February 28, 2005, any gases that contain sulfur dioxide in excess of 
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis,
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average 
basis, or
    (iii) 10 percent of the potential combustion concentration (90 
percent reduction) on a 30-day rolling average basis.
    (k) 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, and 
that is located in a noncontinental area, any gases that contain sulfur 
dioxide in excess of the applicable emission limitation specified in 
paragraphs (k)(1) and (2) of this section.
    (1) For an affected facility that burns solid or solid-derived 
fuel, the owner or operator shall not cause to be discharged into the 
atmosphere any gases that contain sulfur dioxide in excess of 520 ng/J 
(1.2 lb/MMBtu) heat input on a 30-day rolling average basis.
    (2) For an affected facility that burns other than solid or solid-
derived fuel, the owner or operator shall not cause to be discharged 
into the atmosphere any gases that contain sulfur dioxide in excess of 
if the affected facility or 230 ng/J (0.54 lb/MMBtu) heat input on a 
30-day rolling average basis.

0
6. Section 60.44Da is amended by revising paragraph (d) and adding 
paragraphs (e) and (f) to read as follows:

Sec.  60.44Da  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.  
60.48Da(k).
    (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 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, 
except for an IGCC meeting the requirements of paragraph (f) of this 
section, any gases that contain nitrogen oxides (expressed as 
NO2) in excess of the applicable emission limitation 
specified in paragraphs (e)(1) through (3) of this section.
    (1) For an affected facility for which construction commenced after 
February 28, 2005, the owner or operator shall not cause to be 
discharged into the atmosphere any gases that contain nitrogen oxides 
(expressed as NO2) in excess of 130 ng/J (1.0 lb/MWh) gross 
energy output on a 30-day rolling average basis, except as provided 
under Sec.  60.48Da(k).
    (2) For an affected facility for which reconstruction commenced 
after February 28, 2005, the owner or operator shall not cause to be 
discharged into the atmosphere any gases that contain nitrogen oxides 
(expressed as NO2) in excess of either:
    (i) 130 ng/J (1.0 lb/MWh) gross energy output on a 30-day rolling 
average basis, or
    (ii) 47 ng/J (0.11 lb/MMBtu) heat input on a 30-day rolling average 
basis.
    (3) For an affected facility for which modification commenced after 
February 28, 2005, the owner or operator shall not cause to be 
discharged into the atmosphere any gases that contain nitrogen oxides 
(expressed as NO2) in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis, or
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average 
basis.
    (f) On and after the date on which the performance test required to 
be conducted under Sec.  60.8 is completed, the owner or operator of an 
IGCC subject to the provisions of this subpart that burns liquid fuel 
as a supplemental fuel and for which construction, reconstruction, or 
modification commenced after February 28, 2005, shall meet the 
requirements specified in paragraphs (f)(1) through (3) of this 
section.
    (1) The owner or operator shall not cause to be discharged into the 
atmosphere any gases that contain nitrogen oxides (expressed as 
NO2) in excess of 130 ng/J (1.0 lb/MWh) gross energy output 
on a 30-day rolling average basis, except as provided for in paragraphs 
(f)(2) and (3) of this section.
    (2) When burning liquid fuel exclusively or in combination with 
synthetic gas derived from coal such that the liquid fuel contributes 
50 percent or more of the total heat input to the combined cycle 
combustion turbine, the owner or operator shall not cause to be 
discharged into the atmosphere any gases that contain nitrogen oxides 
(expressed as NO2) in excess of 190 ng/J (1.5 lb/MWh) gross 
energy output on a 30-day rolling average basis.
    (3) In cases when during a 30-day rolling average compliance period 
liquid fuel is burned in such a manner to meet the conditions in 
paragraph (f)(2) of this section for only a portion of the 30-day 
period, the owner or operator shall not cause to be discharged into the 
atmosphere any gases that contain nitrogen oxides (expressed as 
NO2) in excess of the computed weighted-average emissions 
limit based on the proportion of gross energy output (in MWh) generated 
during the compliance period for each of emissions limits in paragraphs 
(f)(1) and (2) of this section.

0
7. Section 60.48Da is amended by revising paragraphs (g), (i), (k) 
introductory text, (k)(1) introductory text, (k)(1)(iv), (k)(2) 
introductory text, and adding paragraphs (m), (n), (o), and (p) to read 
as follows:

Sec.  60.48Da  Compliance provisions.

* * * * *
    (g) The owner or operator of an affected facility subject to 
emission limitations in this subpart shall determine compliance as 
follows:
    (1) Compliance with applicable 30-day rolling average 
SO2 and NOX emission limitations is determined by 
calculating the arithmetic average of all hourly emission rates for 
SO2 and NOX for the 30 successive boiler 
operating days, except for data obtained during

[[Page 9879]]

startup, shutdown, malfunction (NOX only), or emergency 
conditions (SO2) only.
    (2) Compliance with applicable SO2 percentage reduction 
requirements is determined based on the average inlet and outlet 
SO2 emission rates for the 30 successive boiler operating 
days.
    (3) Compliance with applicable daily average particulate matter 
emission limitations is determined by calculating the arithmetic 
average of all hourly emission rates for particulate matter each boiler 
operating day, except for data obtained during startup, shutdown, and 
malfunction.
* * * * *
    (i) Compliance provisions for sources subject to Sec.  
60.44Da(d)(1), (e)(1), or (f). The owner or operator of an affected 
facility subject to Sec.  60.44Da(d)(1) or (e)(1) shall calculate 
NOX emissions by multiplying the average hourly 
NOX output concentration, measured according to the 
provisions of Sec.  60.49Da(c), by the average hourly flow rate, 
measured according to the provisions of Sec.  60.49Da(l), and dividing 
by the average hourly gross energy output, measured according to the 
provisions of Sec.  60.49Da(k).
* * * * *
    (k) Compliance provisions for duct burners subject to Sec.  
60.44Da(d)(1) or (e)(1). To determine compliance with the emission 
limitation for NOX required by Sec.  60.44Da(d)(1) or (e)(1) 
for duct burners used in combined cycle systems, either of the 
procedures described in paragraphs (k)(1) and (2) of this section may 
be used:
    (1) The owner or operator of an affected duct burner used in 
combined cycle systems shall determine compliance with the applicable 
NOX emission limitation in Sec. 60.44Da(d)(1) or (e)(1) as 
follows:
* * * * *
    (iv) Compliance with the applicable NOX emission 
limitation in Sec.  60.44Da(d)(1) or (e)(1) is determined by the three-
run average (nominal 1-hour runs) for the initial and subsequent 
performance tests.
    (2) The owner or operator of an affected duct burner used in a 
combined cycle system may elect to determine compliance with the 
applicable NOX emission limitation in Sec.  60.44Da(d)(1) or 
(e)(1) on a 30-day rolling average basis as indicated in paragraphs 
(k)(2)(i) through (iv) of this section.
* * * * *
    (m) Compliance provisions for sources subject to Sec.  
60.43Da(i)(1)(i) or (j)(1)(i). The owner or operator of an affected 
facility subject to Sec.  60.43Da(i)(1)(i) or (j)(1)(i) shall calculate 
SO2 emissions by multiplying the average hourly 
SO2 output concentration, measured according to the 
provisions of Sec.  60.49Da(b), by the average hourly flow rate, 
measured according to the provisions of Sec.  60.49Da(l), and divided 
by the average hourly gross energy output, measured according to the 
provisions of Sec.  60.49Da(k).
    (n) Compliance provisions for sources subject to Sec.  
60.42Da(c)(1). The owner or operator of an affected facility subject to 
Sec.  60.42Da(c)(1) shall calculate particulate matter emissions by 
multiplying the average hourly particulate matter output concentration, 
measured according to the provisions of Sec.  60.49Da(t), by the 
average hourly flow rate, measured according to the provisions of Sec.  
60.49Da(l), and divided by the average hourly gross energy output, 
measured according to the provisions of Sec.  60.49Da(k). Compliance 
with the emission limit is determined by calculating the arithmetic 
average of the hourly emission rates computed for each boiler operating 
day.
    (o) Compliance provisions for sources subject to Sec.  
60.42Da(c)(2) or (d). Except as provided for in paragraph (p) of this 
section, the owner or operator of an affected facility for which 
construction, reconstruction, or modification commenced after February 
28, 2005, shall demonstrate compliance with each applicable emission 
limit according to the requirements in paragraphs (o)(1) through (o)(5) 
of this section.
    (1) Conduct an initial performance test according to the 
requirements in Sec.  60.50Da to demonstrate compliance by the 
applicable date specified in Sec.  60.8(a) and, thereafter, conduct the 
performance test annually, and
    (2) An owner or operator must use opacity monitoring equipment as 
an indicator of continuous particulate matter control device 
performance and demonstrate compliance with Sec.  60.42Da(b). In 
addition, baseline parameters shall be established as the highest 
hourly opacity average measured during the performance test. If any 
hourly average opacity measurement is more than 110 percent of the 
baseline level, the owner or operator will conduct another performance 
test within 60 days to demonstrate compliance. A new baseline is 
established during each stack test. The new baseline shall not exceed 
the opacity limit specified in Sec.  60.42Da(b), and
    (3) An owner or operator using an ESP to comply with the applicable 
emission limits shall use voltage and secondary current monitoring 
equipment to measure voltage and secondary current to the ESP. Baseline 
parameters shall be established as average rates measured during the 
performance test. If a 3-hour average voltage and secondary current 
average deviates more than 10 percent from the baseline level, the 
owner or operator will conduct another performance test within 60 days 
to demonstrate compliance. A new baseline is established during each 
stack test, and
    (4) An owner or operator using a fabric filter to comply with the 
applicable emission limits shall install, calibrate, maintain, and 
continuously operate a bag leak detection system according to 
paragraphs (o)(4)(i) through (viii) of this section.
    (i) Install and operate a bag leak detection system for each 
exhaust stack of the fabric filter.
    (ii) Each bag leak detection system must be installed, operated, 
calibrated, and maintained in a manner consistent with the 
manufacturer's written specifications and recommendations and in 
accordance with the guidance provided in EPA-454/R-98-015, September 
1997.
    (iii) The bag leak detection system must be certified by the 
manufacturer to be capable of detecting particulate matter emissions at 
concentrations of 10 milligrams per actual cubic meter or less.
    (iv) The bag leak detection system sensor must provide output of 
relative or absolute particulate matter loadings.
    (v) The bag leak detection system must be equipped with a device to 
continuously record the output signal from the sensor.
    (vi) The bag leak detection system must be equipped with an alarm 
system that will sound automatically when an increase in relative 
particulate matter emissions over a preset level is detected. The alarm 
must be located where it is easily heard by plant operating personnel. 
Corrective actions must be initiated within 1 hour of a bag leak 
detection system alarm. If the alarm is engaged for more than 5 percent 
of the total operating time on a 30-day rolling average, a performance 
test must be performed within 60 days to demonstrate compliance.
    (vii) For positive pressure fabric filter systems that do not duct 
all compartments of cells to a common stack, a bag leak detection 
system must be installed in each baghouse compartment or cell.
    (viii) Where multiple bag leak detectors are required, the system's 
instrumentation and alarm may be shared among detectors, and
    (5) An owner or operator of a modified affected source electing to 
meet the emission limitations in

[[Page 9880]]

Sec.  60.42Da(d) shall determine the percent reduction in particulate 
matter by using the emission rate for particulate matter determined by 
the performance test conducted according to the requirements in 
paragraph (o)(1) of this section and the ash content on a mass basis of 
the fuel burned during each performance test run as determined by 
analysis of the fuel as fired.
    (p) As an alternative to meeting the compliance provisions 
specified in paragraph (o) of this section, an owner or operator may 
elect to install, certify, maintain, and operate a continuous emission 
monitoring system measuring particulate matter emissions discharged 
from the affected facility to the atmosphere and record the output of 
the system as specified in paragraphs (p)(1) through (p)(8) of this 
section.
    (1) The owner or operator shall submit a written notification to 
the Administrator of intent to demonstrate compliance with this subpart 
by using a continuous monitoring system measuring particulate matter. 
This notification shall be sent at least 30 calendar days before the 
initial startup of the monitor for compliance determination purposes. 
The owner or operator may discontinue operation of the monitor and 
instead return to demonstration of compliance with this subpart 
according to the requirements in paragraph (o) of this section by 
submitting written notification to the Administrator of such intent at 
least 30 calendar days before shutdown of the monitor for compliance 
determination purposes.
    (2) Each continuous emission monitor shall be installed, certified, 
operated, and maintained according to the requirements in Sec.  
60.49Da(v).
    (3) The initial performance evaluation shall be completed no later 
than 180 days after the date of initial startup of the affected 
facility, as specified under Sec.  60.8 of subpart A of this part or 
within 180 days of the date of notification to the Administrator 
required under paragraph (p)(1) of this section, whichever is later.
    (4) Compliance with the applicable emissions limit shall be 
determined based on the 24-hour daily (block) average of the hourly 
arithmetic average emissions concentrations using the continuous 
monitoring system outlet data. The 24-hour block arithmetic average 
emission concentration shall be calculated using EPA Reference Method 
19, section 4.1.
    (5) At a minimum, valid continuous monitoring system hourly 
averages shall be obtained for 90 percent of all operating hours on a 
30-day rolling average.
    (i) At least two data points per hour shall be used to calculate 
each 1-hour arithmetic average.
    (ii) [Reserved]
    (6) The 1-hour arithmetic averages required shall be expressed in 
ng/J, MMBtu/h, or lb/MWh and shall be used to calculate the boiler 
operating day daily arithmetic average emission concentrations. The 1-
hour arithmetic averages shall be calculated using the data points 
required under Sec.  60.13(e)(2) of subpart A of this part.
    (7) All valid continuous monitoring system data shall be used in 
calculating average emission concentrations even if the minimum 
continuous emission monitoring system data requirements of paragraph 
(j)(5) of this section are not met.
    (8) When particulate matter emissions data are not obtained because 
of continuous emission monitoring system breakdowns, repairs, 
calibration checks, and zero and span adjustments, emissions data shall 
be obtained by using other monitoring systems as approved by the 
Administrator or EPA Reference Method 19 to provide, as necessary, 
valid emissions data for a minimum of 90 percent of all operating hours 
per 30-day rolling average.

0
8. Section 60.49Da is amended by revising paragraphs (a), (b)(2), (f), 
(k)(3), (l), and (o), and adding paragraphs (t), (u), and (v) to read 
as follows:

Sec.  60.49Da  Emission monitoring.

    (a) Except as provided for in paragraphs (t) and (u) of this 
section, the owner or operator of an affected facility, shall install, 
calibrate, maintain, and operate a continuous monitoring system, and 
record the output of the system, for measuring the opacity of emissions 
discharged to the atmosphere, except where gaseous fuel is the only 
fuel combusted. If opacity interference due to water droplets exists in 
the stack (for example, from the use of an FGD system), the opacity is 
monitored upstream of the interference (at the inlet to the FGD 
system). If opacity interference is experienced at all locations (both 
at the inlet and outlet of the sulfur dioxide control system), 
alternate parameters indicative of the particulate matter control 
system's performance are monitored (subject to the approval of the 
Administrator).
    (b) * * *
    (2) For a facility that qualifies under the numerical limit 
provisions of Sec.  60.43Da(d), (i), (j), or (k) sulfur dioxide 
emissions are only monitored as discharged to the atmosphere.
* * * * *
    (f)(1) For units that began construction, reconstruction, or 
modification on or before February 28, 2005, the owner or operator 
shall obtain emission data for at least 18 hours in at least 22 out of 
30 successive boiler operating days. If this minimum data requirement 
cannot be met with a continuous monitoring system, the owner or 
operator shall supplement emission data with other monitoring systems 
approved by the Administrator or the reference methods and procedures 
as described in paragraph (h) of this section.
    (2) For units that began construction, reconstruction, or 
modification after February 28, 2005, the owner or operator shall 
obtain emission data for at least 90 percent of all operating hours for 
each 30 successive boiler operating days. If this minimum data 
requirement cannot be met with a continuous monitoring system, the 
owner or operator shall supplement emission data with other monitoring 
systems approved by the Administrator or the reference methods and 
procedures as described in paragraph (h) of this section.
* * * * *
    (k) * * *
    (3) For affected facilities generating process steam in combination 
with electrical generation, the gross energy output is determined from 
the gross electrical output measured in accordance with paragraph 
(k)(1) of this section plus 75 percent of the gross thermal output 
(measured relative to ISO conditions) of the process steam measured in 
accordance with paragraph (k)(2) of this section.
* * * * *
    (l) The owner or operator of an affected facility demonstrating 
compliance with an output-based standard under Sec.  60.42Da, Sec.  
60.43Da, Sec.  60.44Da, or Sec.  60.45Da shall install, certify, 
operate, and maintain a continuous flow monitoring system meeting the 
requirements of Performance Specification 6 of appendix B and procedure 
1 of appendix F of this subpart, and record the output of the system, 
for measuring the flow of exhaust gases discharged to the atmosphere; 
or
* * * * *
    (o) The owner or operator of a duct burner, as described in Sec.  
60.41Da, which is subject to the NOX standards of Sec.  
60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate 
a continuous emissions monitoring system to measure NOX 
emissions; a wattmeter to measure gross electrical output; meters to 
measure steam flow, temperature, and pressure; and a continuous flow 
monitoring system to

[[Page 9881]]

measure the flow of exhaust gases discharged to the atmosphere.
* * * * *
    (t) The owner or operator of an affected facility demonstrating 
compliance with the output-based emissions limitation under Sec.  
60.42Da(c)(1) shall install, certify, operate, and maintain a 
continuous monitoring system for measuring particulate matter emissions 
according to the requirements of paragraph (v) of this section. An 
owner or operator of an affected source demonstrating compliance with 
the input-based emission limitation under Sec.  60.42Da(c)(2) may 
install, certify, operate, and maintain a continuous monitoring system 
for measuring particulate matter emissions according to the 
requirements of paragraph (v) of this section in lieu of the 
requirements in Sec.  60.48Da(o).
    (u) An owner or operator of an affected source that meets the 
conditions in either paragraph (u)(1) or (2) of this section is 
exempted from the continuous opacity monitoring system requirements in 
paragraph (a) of this section and the monitoring requirements in Sec.  
60.48Da(o).
    (1) A continuous monitoring system for measuring particulate matter 
emissions is used to demonstrate continuous compliance on a boiler 
operating day average with the emissions limitations under Sec.  
60.42Da(a)(1) or Sec.  60.42Da(c)(2) and is installed, certified, 
operated, and maintained on the affected source according to the 
requirements of paragraph (v) of this section.
    (2) The affected source burns only oil that contains no more than 
0.15 weight percent sulfur or liquid or gaseous fuels that when 
combusted without sulfur dioxide emission control, have a sulfur 
dioxide emissions rate equal to or less than or equal to 65 ng/J (0.15 
lb/MMBtu) heat input.
    (v) The owner or operator of an affected facility using a 
continuous emission monitoring system measuring particulate matter 
emissions to meet requirements of this subpart shall install, certify, 
operate, and maintain the continuous monitoring system as specified in 
paragraphs (v)(1) through (v)(3).
    (1) The owner or operator shall conduct a performance evaluation of 
the continuous monitoring system according to the applicable 
requirements of Sec.  60.13, Performance Specification 11 in appendix B 
of this part, and procedure 2 in appendix F of this part.
    (2) During each relative accuracy test run of the continuous 
emission monitoring system required by Performance Specification 11 in 
appendix B of this part, particulate matter and oxygen (or carbon 
dioxide) data shall be collected concurrently (or within a 30-to 60-
minute period) by both the continuous emission monitors and conducting 
performance tests using the following test methods.
    (i) For particulate matter, EPA Reference Method 5, 5B, or 17 shall 
be used.
    (ii) For oxygen (or carbon dioxide), EPA Reference Method 3, 3A, or 
3B, as applicable shall be used.
    (3) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with procedure 2 in appendix F 
of this part. Relative Response Audit's must be performed annually and 
Response Correlation Audits must be performed every 3 years.

0
9. Section 60.50Da is amended by revising paragraph (g)(2) to read as 
follows:

Sec.  60.50Da  Compliance determination procedures and methods.

* * * * *
    (g) * * *
    (2) Use the Equation 1 of this section to determine the 
cogeneration Hg emission rate over a specific compliance period.
[GRAPHIC] [TIFF OMITTED] TR27FE06.000

Where:

ERcogen = Cogeneration Hg emission rate over a compliance 
period in lb/MWh;
E = Mass of Hg emitted from the stack over the same compliance period 
(lb);
Vgrid = Amount of energy sent to the grid over the same 
compliance period (MWh); and
Vprocess = Amount of energy converted to steam for process 
use over the same compliance period (MWh).
* * * * *

Subpart Db--[Amended]

0
10. Section 60.40b is amended by revising paragraph (i) and adding 
paragraphs (k) and (l) to read as follows:

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 
MMBtu/h) 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.)
* * * * *
    (k) Any facility covered by subpart Eb or subpart AAAA of this part 
is not covered by this subpart.
    (l) Any facility covered by an EPA approved State or Federal 
section 111(d)/129 plan implementing subpart Cb or subpart BBBB of this 
part is not covered by this subpart.

0
11. Section 60.41b is amended by adding the definition of 
``Cogeneration'' in alphabetical order and revising the definition of 
``Very low sulfur oil'' to read as follows:

Sec.  60.41b  Definitions.

* * * * *
    Cogeneration, also known as combined heat and power, means a 
facility that simultaneously produces both electric (or mechanical) and 
useful thermal energy from the same primary energy source.
* * * * *
    Very low sulfur oil for units constructed, reconstructed, or 
modified on or before February 28, 2005, means an oil that contains no 
more than 0.5 weight percent sulfur or that, when combusted without 
sulfur dioxide emission control, has a sulfur dioxide emission rate 
equal to or less than 215 ng/J (0.5 lb/MMBtu) heat input. For units 
constructed, reconstructed, or modified after February 28, 2005, very 
low sulfur oil means an oil that contains no more than 0.3 weight 
percent sulfur or that, when combusted without sulfur dioxide emission 
control, has a sulfur dioxide emission rate equal to or less than 140 
ng/J (0.32 lb/MMBtu) heat input.
* * * * *

0
12. Section 60.42b is amended by revising paragraphs (a) introductory 
text, (b), (d) introductory text, and (d)(3) and by adding paragraphs 
(d)(4) and (k) to read as follows:

Sec.  60.42b  Standard for sulfur dioxide.

    (a) Except as provided in paragraphs (b), (c), (d), (j), or (k) of 
this section, on and after the date on which the performance test is 
completed or required to be completed under Sec.  60.8 of this part, 
whichever date comes first, no owner or operator of an affected 
facility that commenced construction,

[[Page 9882]]

reconstruction, or modification on or before February 28, 2005, that 
combusts coal or oil shall cause to be discharged into the atmosphere 
any gases that contain sulfur dioxide in excess of 87 ng/J (0.20 lb/
MMBtu) or 10 percent (0.10) of the potential sulfur dioxide emission 
rate (90 percent reduction) and the emission limit determined according 
to the following formula:
* * * * *
    (b) On and after the date on which the performance test is 
completed or required to be completed under Sec.  60.8 of this part, 
whichever date comes first, no owner or operator of an affected 
facility that commenced construction, reconstruction, or modification 
on or before February 28, 2005, that combusts coal refuse alone in a 
fluidized bed combustion steam generating unit shall cause to be 
discharged into the atmosphere any gases that contain sulfur dioxide in 
excess of 87 ng/J (0.20 lb/MMBtu) or 20 percent (0.20) of the potential 
sulfur dioxide emission rate (80 percent reduction) and 520 ng/J (1.2 
lb/MMBtu) heat input. If coal or oil is fired with coal refuse, the 
affected facility is subject to paragraph (a) or (d) of this section, 
as applicable.
* * * * *
    (d) On and after the date on which the performance test is 
completed or required to be completed under Sec.  60.8 of this part, 
whichever comes first, no owner or operator of an affected facility 
listed in paragraphs (d)(1), (2), (3), or (4) of this section shall 
cause to be discharged into the atmosphere any gases that contain 
sulfur dioxide in excess of 520 ng/J (1.2 lb/million Btu) heat input if 
the affected facility combusts coal, or 215 ng/J (0.5 lb/million Btu) 
heat input if the affected facility combusts oil other than very low 
sulfur oil. Percent reduction requirements are not applicable to 
affected facilities under paragraphs (d)(1), (2), (3) or (4).
* * * * *
    (3) Affected facilities combusting coal or oil, alone or in 
combination with any fuel, in a duct burner as part of a combined cycle 
system where 30 percent (0.30) or less of the heat input to the steam 
generating unit is from combustion of coal and oil in the duct burner 
and 70 percent (0.70) or more of the heat input to the steam generating 
unit is from the exhaust gases entering the duct burner; or
    (4) The affected facility burns coke oven gas alone or in 
combination with any other gaseous fuels.
* * * * *
    (k) 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 
commences construction or reconstruction after February 28, 2005, and 
that combusts coal, oil, gas, a mixture of these fuels, or a mixture of 
these fuels with any other fuels shall cause to be discharged into the 
atmosphere any gases that contain sulfur dioxide in excess of 87 ng/J 
(0.20 lb/MMBtu) heat input or 8 percent (0.08) of the potential sulfur 
dioxide emission rate (92 percent reduction) and 520 ng/J (1.2 lb/
MMBtu) heat input, except as provided in paragraphs (k)(1) or (k)(2). 
Affected facilities subject to this paragraph are also subject to 
paragraphs (e) through (g) of this section.
    (1) Units firing only oil that contains no more than 0.3 weight 
percent sulfur or any individual fuel with a potential sulfur dioxide 
emission rates of 140 ng/J (0.32 lb/MMBtu) heat input or less are 
exempt from all other sulfur dioxide emission limits in this paragraph.
    (2) Units that are located in a noncontinental area and that 
combust coal or oil shall not discharge any gases that contain sulfur 
dioxide in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected 
facility combusts coal, or 230 ng/J (0.54 lb/MMBtu) heat input if the 
affected facility combusts oil.

0
13. Section 60.43b is amended by adding paragraph (h) to read as 
follows:

Sec.  60.43b  Standard for particulate matter.

* * * * *
    (h)(1) 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 
commences construction, reconstruction, or modification after February 
28, 2005, and that combusts coal, oil, gas, 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 (0.030 
lb/MMBtu) heat input, except as provided in paragraphs (h)(2), (h)(3), 
(h)(4), and (h)(5).
    (2) As an alternative to meeting the requirements of paragraph 
(h)(1) of this section, the owner or operator of an affected facility 
for which modification commenced after February 28, 2005, may elect to 
meet the requirements of this paragraph. On and after the date on which 
the performance test required to be conducted under Sec.  60.8 is 
completed, the owner or operator subject to the provisions of this 
subpart shall not cause to be discharged into the atmosphere from any 
affected facility for which modification commenced after February 28, 
2005, any gases that contain particulate matter in excess of:
    (i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion 
of coal, oil, gas, wood, a mixture of these fuels, or a mixture of 
these fuels with any other fuels, and
    (ii) 0.2 percent of the combustion concentration (99.8 percent 
reduction) when combusting coal, oil, gas, wood, a mixture of these 
fuels, or a mixture of these fuels with any other fuels.
    (3) 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 
commences modification after February 28, 2005, and that combusts over 
30 percent wood (by heat input) on an annual basis and has a maximum 
heat input capacity of 73 MW (250 MMBtu/h) or less shall cause to be 
discharged into the atmosphere from that affected facility any gases 
that contain particulate matter emissions in excess of 43 ng/J (0.10 
lb/MMBtu) heat input.
    (4) 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 
commences modification after February 28, 2005, and that combusts over 
30 percent wood (by heat input) on an annual basis and has a maximum 
heat input capacity greater than 73 MW (250 MMBtu/h) shall cause to be 
discharged into the atmosphere from that affected facility any gases 
that contain particulate matter emissions in excess of 37 ng/J (0.085 
lb/MMBtu) heat input.
    (5) 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 
commences construction, reconstruction, or modification after February 
28, 2005, and that combusts only oil that contains no more than 0.3 
weight percent sulfur or other liquid or gaseous fuels with potential 
sulfur dioxide emission rates of 140 ng/J (0.32 lb/MMBtu) heat input or 
less is not subject to the PM or opacity limits in this section.

0
14. Section 60.44b is amended by adding paragraph (l)(3) to read as 
follows:

Sec.  60.44b  Standard for nitrogen oxides.

* * * * *
    (l) * * *

[[Page 9883]]

    (3) After February 27, 2006, units may comply with an optional 
limit of 270 ng/J (2.1 lb/MWh) gross energy output, based on a 30-day 
rolling average. Units complying with this output-based limit must 
demonstrate compliance according to the procedures of Sec.  60.46a 
(i)(1), and must monitor emissions according to Sec.  60.47a(c)(1), 
(c)(2), (k), and (l).

0
15. Section 60.45b is amended by revising the introductory text in 
paragraph (c) and adding paragraph (k) to read as follows:

Sec.  60.45b  Compliance and performance test methods and procedures 
for sulfur dioxide.

* * * * *
    (c) The owner or operator of an affected facility shall conduct 
performance tests to determine compliance with the percent of potential 
sulfur dioxide emission rate (% Ps) and the sulfur dioxide 
emission rate (Es) pursuant to Sec.  60.42b following the 
procedures listed below, except as provided under paragraph (d) and (k) 
of this section.
* * * * *
    (k) Units that burn only oil that contains no more than 0.3 weight 
percent sulfur or fuels with potential sulfur dioxide emission rates of 
140 ng/J (0.32 lb/MMBtu) heat input or less may demonstrate compliance 
by maintaining records of fuel supplier certifications of sulfur 
content of the fuels burned.

0
16. Section 60.46b is amended by revising paragraphs (a) and (b) and 
adding paragraphs (i) and (j) to read as follows:
* * * * *

Sec.  60.46b  Compliance and performance test methods and procedures 
for particulate matter and nitrogen oxides.

    (a) The particulate matter emission standards and opacity limits 
under Sec.  60.43b apply at all times except during periods of startup, 
shutdown, or malfunction, and as specified in paragraphs (i) and (j) of 
this section. The nitrogen oxides emission standards under Sec.  60.44b 
apply at all times.
    (b) Compliance with the particulate matter emission standards under 
Sec.  60.43b shall be determined through performance testing as 
described in paragraph (d) of this section, except as provided in 
paragraph (i) and (j).
* * * * *
    (i) Units burning only oil that contains no more than 0.3 weight 
percent sulfur or liquid or gaseous fuels with a potential sulfur 
dioxide emission rates of 140 ng/J (0.32 lb/MMBtu) heat input or less 
may demonstrate compliance by maintaining fuel supplier certifications 
of the sulfur content of the fuels burned.
    (j) In place of particulate matter testing with EPA Reference 
Method 5, 5B, or 17, an owner or operator may elect to install, 
calibrate, maintain, and operate a continuous emission monitoring 
system for monitoring particulate matter emissions discharged to the 
atmosphere and record the output of the system. The owner or operator 
of an affected facility who elects to continuously monitor particulate 
matter emissions instead of conducting performance testing using EPA 
Method 5, 5B, or 17 shall comply with the requirements specified in 
paragraphs (j)(1) through (j)(13) of this section.
    (1) Notify the Administrator one month before starting use of the 
system.
    (2) Notify the Administrator one month before stopping use of the 
system.
    (3) The monitor shall be installed, evaluated, and operated in 
accordance with Sec.  60.13 of subpart A of this part.
    (4) The initial performance evaluation shall be completed no later 
than 180 days after the date of initial startup of the affected 
facility, as specified under Sec.  60.8 of subpart A of this part or 
within 180 days of notification to the Administrator of use of the 
continuous monitoring system if the owner or operator was previously 
determining compliance by Method 5, 5B, or 17 performance tests, 
whichever is later.
    (5) The owner or operator of an affected facility shall conduct an 
initial performance test for particulate matter emissions as required 
under Sec.  60.8 of subpart A of this part. Compliance with the 
particulate matter emission limit shall be determined by using the 
continuous emission monitoring system specified in paragraph (j) of 
this section to measure particulate matter and calculating a 24-hour 
block arithmetic average emission concentration using EPA Reference 
Method 19, section 4.1.
    (6) Compliance with the particulate matter emission limit shall be 
determined based on the 24-hour daily (block) average of the hourly 
arithmetic average emission concentrations using continuous emission 
monitoring system outlet data.
    (7) At a minimum, valid continuous monitoring system hourly 
averages shall be obtained as specified in paragraphs (j)(7)(i) of this 
section for 75 percent of the total operating hours per 30-day rolling 
average.
    (i) At least two data points per hour shall be used to calculate 
each 1-hour arithmetic average.
    (8) The 1-hour arithmetic averages required under paragraph (j)(7) 
of this section shall be expressed in ng/J or lb/MMBtu heat input and 
shall be used to calculate the boiler operating day daily arithmetic 
average emission concentrations. The 1-hour arithmetic averages shall 
be calculated using the data points required under Sec.  60.13(e)(2) of 
subpart A of this part.
    (9) All valid continuous emission monitoring system data shall be 
used in calculating average emission concentrations even if the minimum 
continuous emission monitoring system data requirements of paragraph 
(j)(7) of this section are not met.
    (10) The continuous emission monitoring system shall be operated 
according to Performance Specification 11 in appendix B of this part.
    (11) During the correlation testing runs of the continuous emission 
monitoring system required by Performance Specification 11 in appendix 
B of this part, particulate matter and oxygen (or carbon dioxide) data 
shall be collected concurrently (or within a 30- to 60-minute period) 
by both the continuous emission monitors and the test methods specified 
in paragraphs (j)(7)(i) of this section.
    (i) For particulate matter, EPA Reference Method 5, 5B, or 17 shall 
be used.
    (ii) For oxygen (or carbon dioxide), EPA reference Method 3, 3A, or 
3B, as applicable shall be used.
    (12) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with procedure 2 in appendix F 
of this part. Relative Response Audit's must be performed annually and 
Response Correlation Audits must be performed every 3 years.
    (13) When particulate matter emissions data are not obtained 
because of continuous emission monitoring system breakdowns, repairs, 
calibration checks, and zero and span adjustments, emissions data shall 
be obtained by using other monitoring systems as approved by the 
Administrator or EPA Reference Method 19 to provide, as necessary, 
valid emissions data for a minimum of 75 percent of total operating 
hours per 30-day rolling average.

0
17. Section Sec.  60.47b is amended by revising paragraphs (a) and (d), 
and adding paragraph (g) to read as follows:

Sec.  60.47b  Emission monitoring for sulfur dioxide.

    (a) Except as provided in paragraphs (b),(f), and (g) of this 
section, the owner or operator of an affected facility subject to the 
sulfur dioxide standards under Sec.  60.42b shall install, calibrate, 
maintain, and operate continuous emission monitoring systems (CEMS)

[[Page 9884]]

for measuring sulfur dioxide concentrations and either oxygen 
(O2) or carbon dioxide (CO2) concentrations and 
shall record the output of the systems. The sulfur dioxide and either 
oxygen or carbon dioxide concentrations shall both be monitored at the 
inlet and outlet of the sulfur dioxide control device.
* * * * *
    (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/MMBtu 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.
* * * * *
    (g) Units burning any fuel with a potential sulfur dioxide emission 
rate of 140 ng/J (0.32 lb/MMBtu) heat input or less are not required to 
conduct emissions monitoring if they maintain fuel supplier 
certifications of the sulfur content of the fuels burned.

0
18. Section 60.48b is amended by revising paragraphs (a), (b) 
introductory text, (d), and adding paragraphs (j) and (k) to read as 
follows:

Sec.  60.48b  Emission monitoring for particulate matter and nitrogen 
oxides.

    (a) The owner or operator of an affected facility subject to the 
opacity standard under Sec.  60.43b shall install, calibrate, maintain, 
and operate a continuous monitoring system for measuring the opacity of 
emissions discharged to the atmosphere and record the output of the 
system, except as provided in paragraphs (j) and (k) of this section.
    (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 Sec.  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/MMBtu 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).
* * * * *
    (j) Units that burn only oil that contains no more than 0.3 weight 
percent sulfur or liquid or gaseous fuels with potential sulfur dioxide 
emission rates of 140 ng/J (0.32 lb/MMBtu) heat input or less are not 
required to conduct PM emissions monitoring if they maintain fuel 
supplier certifications of the sulfur content of the fuels burned.
    (k) Owners or operators complying with the PM emission limit by 
using a PM CEMs monitor instead of monitoring opacity must calibrate, 
maintain, and operate a continuous monitoring system, and record the 
output of the system, for PM emissions discharged to the atmosphere as 
specified in Sec.  60.46b(j). The continuous monitoring systems 
specified in paragraph Sec.  60.46b(j) shall be operated and data 
recorded during all periods of operation of the affected facility 
except for continuous monitoring system breakdowns and repairs. Data is 
recorded during calibration checks, and zero and span adjustments.

Subpart Dc--[Amended]

0
19. Section 60.40c is amended by adding paragraphs (e), (f), and (g) 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 MMBtu/h) 
heat input of fossil fuel but less than or equal to 29 MW (100 MMBtu/h) 
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).
    (f) Any facility covered by subpart AAAA of this part is not 
covered by this subpart.
    (g) Any facility covered by an EPA approved State or Federal 
section 111(d)/129 plan implementing subpart BBBB of this part is not 
covered by this subpart.

0
20. 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.
* * * * *

0
21. Section 60.42c is amended by revising paragraphs (a), (b) 
introductory text, and (b)(1) to read as follows:

Sec.  60.42c  Standard for sulfur dioxide.

    (a) Except as provided in paragraphs (b), (c), and (e) of this 
section, on and after the date on which the performance test is 
completed or required to be completed under Sec.  60.8 of this part, 
whichever date comes first, the owner or operator of an affected 
facility that combusts only coal shall neither: Cause to be discharged 
into the atmosphere from the affected facility any gases that contain 
SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 
percent (0.10) of the potential SO2 emission rate (90 
percent reduction), nor cause to be discharged into the atmosphere from 
the affected facility any gases that contain SO2 in excess 
of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is combusted with other 
fuels, the affected facility is subject to the 90 percent 
SO2 reduction requirement specified in this paragraph and 
the emission limit is determined pursuant to paragraph (e)(2) of this 
section.
    (b) Except as provided in paragraphs (c) and (e) of this section, 
on and after the date on which the performance test is completed or 
required to be completed under Sec.  60.8 of this part, whichever date 
comes first, the owner or operator of an affected facility that:
    (1) Combusts only coal refuse alone in a fluidized bed combustion 
steam generating unit shall neither:
    (i) Cause to be discharged into the atmosphere from that affected 
facility any gases that contain SO2 in excess of 87 ng/J 
(0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential 
SO2 emission rate (80 percent reduction), nor

[[Page 9885]]

    (ii) Cause to be discharged into the atmosphere from that affected 
facility any gases that contain SO2 in excess of 
SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal 
is fired with coal refuse, the affected facility subject to paragraph 
(a) of this section. If oil or any other fuel (except coal) is fired 
with coal refuse, the affected facility is subject to the 90 percent 
SO2 reduction requirement specified in paragraph (a) of this 
section and the emission limit is determined pursuant to paragraph 
(e)(2) of this section.
* * * * *

0
22. Section 60.43c is amended by adding paragraph (e) to read as 
follows:

Sec.  60.43c  Standard for particulate matter.

* * * * *
    (e)(1) 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 
commences construction, reconstruction, or modification after February 
28, 2005, and that combusts coal, oil, gas, wood, a mixture of these 
fuels, or a mixture of these fuels with any other fuels and has a heat 
input capacity of 8.7 MW (30 MMBtu/h) or greater 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 (0.030 
lb/MMBtu) heat input, except as provided in paragraphs (e)(2) and 
(e)(3) of this section. Affected facilities subject to this paragraph, 
are also subject to the requirements of paragraphs (c) and (d) of this 
section.
    (2) As an alternative to meeting the requirements of paragraph 
(e)(1) of this section, the owner or operator of an affected facility 
for which modification commenced after February 28, 2005, may elect to 
meet the requirements of this paragraph. On and after the date on which 
the performance test required to be conducted under Sec.  60.8 is 
completed, the owner or operator subject to the provisions of this 
subpart shall not cause to be discharged into the atmosphere from any 
affected facility for which modification commenced after February 28, 
2005, any gases that contain particulate matter in excess of:
    (i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion 
of coal, oil, gas, wood, a mixture of these fuels, or a mixture of 
these fuels with any other fuels, and
    (ii) 0.2 percent of the combustion concentration (99.8 percent 
reduction) when combusting coal, oil, gas, wood, a mixture of these 
fuels, or a mixture of these fuels with any other fuels.
    (3) 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 
commences modification after February 28, 2005, and that combusts over 
30 percent wood (by heat input) on an annual basis and has a heat input 
capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged 
into the atmosphere from that affected facility any gases that contain 
particulate matter emissions in excess of 43 ng/J (0.10 lb/MMBtu) heat 
input.

0
23. Section 60.45c is amended by revising the introductory text in 
paragraph (a) and adding paragraphs (c) and (d) to read as follows:

Sec.  60.45c  Compliance and performance test methods and procedures 
for particulate matter.

    (a) The owner or operator of an affected facility subject to the PM 
and/or opacity standards under Sec.  60.43c shall conduct an initial 
performance test as required under Sec.  60.8, and shall conduct 
subsequent performance tests as requested by the Administrator, to 
determine compliance with the standards using the following procedures 
and reference methods, except as specified in paragraph (c) and (d) of 
this section.
* * * * *
    (c) Units that burn only oil containing no more than 0.5 weight 
percent sulfur or liquid or gaseous fuels with potential sulfur dioxide 
emission rates of 230 ng/J (0.54 lb/MMBtu) heat input or less are not 
required to conduct emissions monitoring if they maintain fuel supplier 
certifications of the sulfur content of the fuels burned.
    (d) In place of particulate matter testing with EPA Reference 
Method 5, 5B, or 17, an owner or operator may elect to install, 
calibrate, maintain, and operate a continuous emission monitoring 
system for monitoring particulate matter emissions discharged to the 
atmosphere and record the output of the system. The owner or operator 
of an affected facility who elects to continuously monitor particulate 
matter emissions instead of conducting performance testing using EPA 
Method 5, 5B, or 17 shall install, calibrate, maintain, and operate a 
continuous emission monitoring system and shall comply with the 
requirements specified in paragraphs (d)(1) through (d)(13) of this 
section.
    (1) Notify the Administrator 1 month before starting use of the 
system.
    (2) Notify the Administrator 1 month before stopping use of the 
system.
    (3) The monitor shall be installed, evaluated, and operated in 
accordance with Sec.  60.13 of subpart A of this part.
    (4) The initial performance evaluation shall be completed no later 
than 180 days after the date of initial startup of the affected 
facility, as specified under Sec.  60.8 of subpart A of this part or 
within 180 days of notification to the Administrator of use of the 
continuous monitoring system if the owner or operator was previously 
determining compliance by Method 5, 5B, or 17 performance tests, 
whichever is later.
    (5) The owner or operator of an affected facility shall conduct an 
initial performance test for particulate matter emissions as required 
under Sec.  60.8 of subpart A of this part. Compliance with the 
particulate matter emission limit shall be determined by using the 
continuous emission monitoring system specified in paragraph (d) of 
this section to measure particulate matter and calculating a 24-hour 
block arithmetic average emission concentration using EPA Reference 
Method 19, section 4.1.
    (6) Compliance with the particulate matter emission limit shall be 
determined based on the 24-hour daily (block) average of the hourly 
arithmetic average emission concentrations using continuous emission 
monitoring system outlet data.
    (7) At a minimum, valid continuous monitoring system hourly 
averages shall be obtained as specified in paragraph (d)(7)(i) of this 
section for 75 percent of the total operating hours per 30-day rolling 
average.
    (i) At least two data points per hour shall be used to calculate 
each 1-hour arithmetic average.
    (ii) [Reserved]
    (8) The 1-hour arithmetic averages required under paragraph (d)(7) 
of this section shall be expressed in ng/J or lb/MMBtu heat input and 
shall be used to calculate the boiler operating day daily arithmetic 
average emission concentrations. The 1-hour arithmetic averages shall 
be calculated using the data points required under Sec.  60.13(e)(2) of 
subpart A of this part.
    (9) All valid continuous emission monitoring system data shall be 
used in calculating average emission concentrations even if the minimum 
continuous emission monitoring system data requirements of paragraph 
(d)(7) of this section are not met.
    (10) The continuous emission monitoring system shall be operated 
according to Performance Specification 11 in appendix B of this part.
    (11) During the correlation testing runs of the continuous emission 
monitoring system required by Performance Specification 11 in

[[Page 9886]]

appendix B of this part, particulate matter and oxygen (or carbon 
dioxide) data shall be collected concurrently (or within a 30- to 60-
minute period) by both the continuous emission monitors and the test 
methods specified in paragraph (d)(7)(i) of this section.
    (i) For particulate matter, EPA Reference Method 5, 5B, or 17 shall 
be used.
    (ii) For oxygen (or carbon dioxide), EPA reference Method 3, 3A, or 
3B, as applicable shall be used.
    (12) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with procedure 2 in appendix F 
of this part. Relative Response Audit's must be performed annually and 
Response Correlation Audits must be performed every 3 years.
    (13) When particulate matter emissions data are not obtained 
because of continuous emission monitoring system breakdowns, repairs, 
calibration checks, and zero and span adjustments, emissions data shall 
be obtained by using other monitoring systems as approved by the 
Administrator or EPA Reference Method 19 to provide, as necessary, 
valid emissions data for a minimum of 75 percent of total operating 
hours on a 30-day rolling average.

0
24. Section 60.47c is amended by revising paragraph (a) and adding 
paragraphs (c) and (d) to read as follows:

Sec.  60.47c  Emission monitoring for particulate matter.

    (a) The owner or operator of an affected facility combusting coal, 
oil, gas, or wood that is subject to the opacity standards under Sec.  
60.43c shall install, calibrate, maintain, and operate a COMS for 
measuring the opacity of the emissions discharged to the atmosphere and 
record the output of the system, except as specified in paragraphs (c) 
and (d) of this section.
* * * * *
    (c) Units that burn only oil that contains no more than 0.5 weight 
percent sulfur or liquid or gaseous fuels with potential sulfur dioxide 
emission rates of 230 ng/J (0.54 lb/MMBtu) heat input or less are not 
required to conduct PM emissions monitoring if they maintain fuel 
supplier certifications of the sulfur content of the fuels burned.
    (d) Owners or operators complying with the PM emission limit by 
using a PM CEMS monitor instead of monitoring opacity must calibrate, 
maintain, and operate a continuous monitoring system, and record the 
output of the system, for PM emissions discharged to the atmosphere as 
specified in Sec.  60.45c(d). The continuous monitoring systems 
specified in paragraph Sec.  60.45c(d) shall be operated and data 
recorded during all periods of operation of the affected facility 
except for continuous monitoring system breakdowns and repairs. Data is 
recorded during calibration checks, and zero and span adjustments.

0
25. Section 60.48c is amended by revising paragraph (g) to read as 
follows:

Sec.  60.48c  Reporting and recordkeeping requirements.

* * * * *
    (g) The owner or operator of each affected facility shall record 
and maintain records of the amounts of each fuel combusted during each 
day. The owner or operator of an affected facility that only burns very 
low sulfur fuel oil or other liquid or gaseous fuels with potential 
sulfur dioxide emissions rate of 140 ng/J (0.32 lb/MMBtu) heat input or 
less shall record and maintain records of the fuels combusted during 
each calendar month.
* * * * *
[FR Doc. 06-1460 Filed 2-24-06; 8:45 am]

BILLING CODE 6560-50-P