[Federal Register: February 9, 2007 (Volume 72, Number 27)]
[Proposed Rules]
[Page 6319-6375]
[DOCID:fr09fe07-16]

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Part II

Environmental Protection Agency

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40 CFR Part 60

Air Pollution; Standards of Performance for New Stationary Sources:
Fossil-Fuel-Fired Steam Generators and Electric Utility and Industrial-
Commercial-Institutional Steam Generating Units; Reconsideration, etc.;
Proposed Rule

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2005-0031; FRL-8275-9]
RIN 2060-AN97

Standards of Performance for Fossil-Fuel-Fired Steam Generators
for Which Construction Is Commenced After August 17, 1971; 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; Reconsideration and Amendments

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing to amend the new source performance standards
(NSPS) for electric utility steam generating units and industrial-
commercial-institutional steam generating units. On February 27, 2006,
EPA promulgated amendments to the NSPS for steam generating units. EPA
is proposing to amend specific provisions in the NSPS for steam
generating units to resolve issues and questions raised by petitioners
for reconsideration of the promulgated amendments, and to correct
technical and editorial errors that have been identified since
promulgation. In addition, the proposed rule would update the
grammatical style of the four NSPS steam generating unit subparts to be
consistent across all of the subparts.

DATES: Comments. Comments must be received on or before March 12, 2007,
unless a public hearing is requested by February 20, 2007. If a timely
hearing request is submitted, the public hearing will be held on
February 26, 2007 and we must receive written comments on or before
March 26, 2007.

ADDRESSES: Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2005-0031, by one of the following methods:
     http://www.regulations.gov. Follow the on-line

instructions for submitting comments.
     E-mail<EMAIL_ADDRESS>     By Facsimile:<PHONE_NUMBER>.
     Mail: Air and Radiation Docket, U.S. EPA, Mail Code 6102T,
1200 Pennsylvania Ave., NW., Washington, DC 20460. Please include a
total of two copies. EPA requests a separate copy also be sent to the
contact person identified below (see FOR FURTHER INFORMATION CONTACT).
     Hand Delivery: EPA Docket Center, Docket ID Number EPA-HQ-
OAR-2005-0031, EPA West Building, 1301 Constitution Ave., NW., Room
3334, Washington, DC, 20004. Such deliveries are accepted only during
the Docket's normal hours of operation, and special arrangements should
be made for deliveries of boxed information.
    Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2005-0031. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
http://www.regulations.gov, including any personal information

provided, unless the comment includes information claimed to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected through regulations.gov or e-
mail. The http://www.regulations.gov Web site is an ``anonymous access''

systems, which means EPA will not know your identity or contact
information unless you provide it in the body of your comment. If you
send an e-mail comment directly to EPA without going through
http://www.regulations.gov, your e-mail address will be automatically captured

and included as part of the comment that is placed in the public docket
and made available on the Internet. If you submit an electronic
comment, EPA recommends that you include your name and other contact
information in the body of your comment and with any disk or CD-ROM you
submit. If EPA cannot read your comment due to technical difficulties
and cannot contact you for clarification, EPA may not be able to
consider your comment. Electronic files should avoid the use of special
characters, any form of encryption, and be free of any defects or
viruses. For additional information about EPA's public docket visit the
EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm.

    Docket: All documents in the docket are listed in the
http://www.regulations.gov index. 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, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in http://www.regulations.gov or in hard copy at the Air and Radiation

Docket EPA/DC, EPA West, Room 3334, 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<PHONE_NUMBER>, and the telephone
number for the Air and Radiation Docket is<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Mr. Christian Fellner, Energy
Strategies Group, Sector Policies and Programs Division (D243-01), U.S.
EPA, Research Triangle Park, NC 27711, telephone number<PHONE_NUMBER>,
facsimile number<PHONE_NUMBER>, electronic mail (e-mail) address:
<EMAIL_ADDRESS>

SUPPLEMENTARY INFORMATION: Entities Table. Entities potentially
affected by this proposed action include, but are not limited to, the
following:

------------------------------------------------------------------------
                                                 Examples of potentially
            Category             NAICS code \1\     regulated entities
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Industry.......................          221112  Fossil fuel-fired
                                                  electric utility steam
                                                  generating units.
Federal Government.............           22112  Fossil fuel-fired
                                                  electric utility steam
                                                  generating units owned
                                                  by the Federal
                                                  Government.
State/local/tribal government..           22112  Fossil fuel-fired
                                                  electric utility steam
                                                  generating units owned
                                                  by municipalities.
                                         921150  Fossil fuel-fired
                                                  electric utility steam
                                                  generating units
                                                  located in Indian
                                                  Country.
Any industrial, commercial, or              211  Extractors of crude
 institutional facility using a                   petroleum and natural
 steam generating unit as                         gas.
 defined in 60.40b or 60.40c.
                                            321  Manufacturers of lumber
                                                  and wood products.
                                            322  Pulp and paper mills.
                                            325  Chemical manufacturers.
                                            324  Petroleum refiners and
                                                  manufacturers of coal
                                                  products.
                                  316, 326, 339  Manufacturers of rubber
                                                  and miscellaneous
                                                  plastic products.

                                            331  Steel works, blast
                                                  furnaces.
                                            332  Electroplating,
                                                  plating, polishing,
                                                  anodizing, and
                                                  coloring.
                                            336  Manufacturers of motor
                                                  vehicle parts and
                                                  accessories.
                                            221  Electric, gas, and
                                                  sanitary services.
                                            622  Health services.
                                            611  Educational Services.
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\1\ North American Industry Classification System (NAICS) code.

    This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by the
proposed rule. To determine whether your facility is regulated by the
proposed rule, you should examine the applicability criteria in Sec.
60.40a, Sec.  60.40b, or Sec.  60.40c of 40 CFR part 60. If you have
any questions regarding the applicability of the proposed rule to a
particular entity, contact the person listed in the preceding FOR
FURTHER INFORMATION CONTACT section. World Wide Web (WWW). Following
the Administrator's signature, a copy of the proposed amendments will
be posted on the Technology Transfer Network's (TTN) policy and
guidance page for newly proposed or promulgated rules at http://www.epa.gov/ttn/oarpg.
 The TTN provides information and technology

exchange in various areas of air pollution control.
    Public Hearing. If a public hearing is requested, it will be held
at 10 a.m. at the EPA Facility Complex in Research Triangle Park, North
Carolina or at an alternate site nearby. Contact Mr. Christian Fellner
at<PHONE_NUMBER> to request a hearing, to request to speak at a public
hearing, to determine if a hearing will be held, or to determine the
hearing location.
    Outline. The information presented in this preamble is organized as
follows:

I. Background
II. Proposed Amendments
    A. Proposed Substantive Amendments to Subpart D
    B. Proposed Substantive Amendments to Subpart Da
    C. Proposed Substantive Amendments to Subpart Db
    D. Proposed Substantive Amendments to Subpart Dc
III. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paper 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 Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer Advancement Act

Background

    EPA promulgated amendments to the new source performance standards
for steam generating units on February 27, 2006 (71 FR 9866). The
amendments added new emissions limits and compliance requirements
applicable to units constructed, modified, or reconstructed after
February 28, 2005, for electric utility steam generating units in 40
CFR part 60, subpart Da; industrial-commercial-institutional steam
generating units in 40 CFR part 60, subpart Db; and small industrial-
commercial-institutional steam generating units in 40 CFR part 60,
subpart Dc. In addition, an alternative sulfur dioxide (SO2)
emissions limit was added to subparts Db and Dc for steam generating
units for which construction, modification, or reconstruction was
commenced prior to February 28, 2005.
    Petitions for reconsideration of the amendments were filed by the
Utility Air Regulatory Group and the Council of Industrial Boiler
Owners. The EPA has decided to grant reconsideration to the amendments
to the extent specified in the proposed rule. The amendments proposed
by this action address issues for which the petitioners requested
reconsideration\1\ (see docket entries EPA-HQ-OAR-2005-0031-0224 and
EPA-HQ-OAR-2005-0031-0225).
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    \1\ An issue EPA is not granting reconsideration on is UARG's
request ``EPA should also clarify that PM CEMS data would not be
`credible evidence' of a violation of the applicable PM standard for
a source during a period for which the source has not otped to use
PM CEMS to determine compliance.''
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    As part of this action, EPA is also proposing to amend other rule
language to correct technical omissions, typographical errors, cross-
reference errors, grammatical errors, and various other issues that
have been identified since promulgation. The proposed amendments would
not significantly change EPA's original projections for the rule's
compliance costs, environmental benefits, burden on industry, or the
number of affected facilities.
    Finally, as part of the February 28, 2005, proposal to the steam
generating unit NSPS, EPA proposed several amendments designed to
minimize the continuous emission monitoring systems (CEMS) burden for
sources subject to both the NSPS under 40 CFR part 60 and the acid rain
regulations under 40 CFR part 75 (70 FR 9720). The intent of these
proposed amendments is to address the inconsistent and duplicative CEM
requirements in the two rules while still maintaining the integrity of
the separate NSPS and acid rain programs. EPA received five comment
letters on these proposed amendments. The comments were generally
supportive of the amendments, but due to the need for additional
internal EPA review, EPA did not include the CEM protocol amendments
with the other steam generating unit NSPS amendments that were
promulgated on February 27, 2006. EPA intends to include the final CEM
requirement amendments with the final action of this reconsideration. A
detailed description of the proposed amendments to the CEM requirements
is available in the docket.

II. Proposed Amendments

    EPA is proposing to amend 40 CFR part 60, subparts D, Da, Db, and
Dc to clarify the intent for applying and implementing specific rule
requirements and to correct unintentional technical omissions and
editorial errors. A summary of the proposed substantive amendments to
the NSPS for steam generating units and the rationale for these
amendments are presented below.
    In addition, EPA is proposing to republish 40 CFR 60.17
(Incorporations by reference) and subparts D, Da, Db, and Dc in their
entirety. The proposed amendments include updating 40 CFR 60.17 to be
consistent with the recent formatting style used in subpart KKKK of 40
CFR part 60 and revising the wording and writing style to be more
consistent across all the NSPS subparts applicable to steam generating
units. EPA does not intend for these editorial revisions to
substantively change any of

the technical or administrative requirements of the subparts and has
concluded that these do not do so. The various subparts were
promulgated at different times and, therefore, vary somewhat in style.
EPA has concluded that it is appropriate at this time to reconcile
these various styles in order to provide consistency across the
subparts. To the extent that the editorial revisions do effect any
unintended substantive changes, EPA will correct the problem in taking
final action on the proposed rule. The docket for this rulemaking
(Docket ID No. EPA-HQ-OAR-2005-0031) contains complete redline/strike-
out versions of each subpart, which allows direct comparison of all of
the proposed amended rule text with the existing rule text.

A. Proposed Substantive Amendments to Subpart D

1. Alternative Emissions Standards
    Subpart D of 40 CFR part 60 establishes nitrogen oxides
(NOX), SO2, and PM emission standards for steam
generating units that began construction between August 17, 1971 and
September 18, 1978. Continuous compliance with these emissions
standards is determined by comparison of the applicable emissions limit
to the actual NOX and SO2 emissions measured by
CEMS and averaged over three contiguous 1-hour periods.
    When subpart D was originally developed, the NOX
standards were achievable with the use of available combustion
controls, and the SO2 standards were achievable by burning
low-sulfur fuels. EPA has concluded some of the electric utility steam
generating units presently subject to subpart D will install additional
post-combustion controls because they are subject to NOX and
SO2 emissions standards implemented by other air programs
after subpart D was promulgated. In many cases, compliance with these
other NOX and SO2 standards is based on 30-day or
longer rolling averages instead of the 3-hour averaging period used for
the subpart D standards. For example, a coal-fired electric utility
steam generating unit subject to both the subpart D NSPS and the
Regional Haze Regulations must meet: (1) A 3-hour average
SO2 emission of 1.2 pounds per million Btu of heat input
(lb/MMBtu) and (2) the Best Available Retrofit Technology (BART)
presumptive 30-day rolling average SO2 emissions limit of
0.15 lb/MMBtu or 95 percent reduction in potential emissions. This
requires the owners and operators of the units subject to both subpart
D and BART to collect and record data and perform compliance
determinations for two different averaging periods.
    EPA is proposing to allow owners and operators of steam generating
units subject to subpart D to elect to comply with the NOX
and SO2 standards for modified units under subpart Da. These
standards are based on 30-day rolling averages and would be an
alternative to meeting the existing applicable 3-hour average
NOX and SO2 standards in subpart D. Adding these
alternative 30-day average NOX and SO2 standards
to subpart D would simplify the compliance requirements and add fuel
choice flexibility.
    Since averaging time is an important consideration when selecting
the numerical level for an emissions standard, the limits EPA is
proposing as an alternative to the existing 3-hour average based
standards are significantly lower and represent emissions levels
achieved by electric utility steam generating units retrofitted with
post-combustion controls. As an alternative to the existing 3-hour
average subpart D SO2 standard of 0.8 or 1.2 lb/MMBtu
(depending on fuel type burned), EPA is proposing to allow a
SO2 fuel neutral emissions limit of 1.4 pounds per megawatts
hour of output (lb/MWh), 0.15 lb/MMBtu, or 90 percent reduction of
potential SO2 emissions based on a 30-day rolling average.
This emissions limit could be applied to any electric utility steam
generating unit subject to subpart D regardless of the type of fuel
burned. For the NOX emissions limit, EPA is proposing a fuel
neutral 30-day rolling average emissions limit of 1.4 lb/MWh or 0.15
lb/MMBtu as an alternative to the existing subpart D 3-hour
NOX emissions limits of 0.2 to 0.8 lb/MMBtu (depending on
the type of fuel burned).
    To use the alternative standards, an owner or operator would
request permission from the EPA Administrator for the affected source
to begin complying with the alternative 30-day average NOX
and SO2 standards. After demonstrating initial compliance
with the 30-day average standards, the 30-day average standards would
apply to the source for the remainder of the operating life of the
unit. The decision to comply with the alternative 30-day average
NOX and SO2 emissions standards would be a one-
time and irreversible decision, i.e., an owner or operator would not be
allowed to switch between complying with the 3-hour average standards
and the 30-day rolling average standards. For owners and operators who
decide to continue to demonstrate compliance based on the 3-hour
rolling average standards, demonstrating that a unit achieved the 30-
day average standards does not remove the obligation to demonstrate
continuous compliance with the 3-hour average based standards.
2. Alternative PM CEMS Monitoring
    The amendments to subpart Da in 40 CFR part 60, promulgated on
February 27, 2006, allow affected owners and operators of electric
utility steam generating units subject to subpart Da to install and
operate a CEMS that measures PM as an alternative to continuously
monitoring opacity. EPA is proposing that the same alternative
monitoring provisions be added to subpart D. EPA has concluded that
since PM CEMS measure the pollutant of primary interest they provide
adequate assurance of PM control device performance, and continuous
opacity monitoring is an unnecessary burden to affected sources using
PM CEMS.
3. Alternate Carbon Monoxide Monitoring for Oil-Fired Steam Generating
Units
    Under subpart D, all affected electric utility steam generating
units (including those that only burn natural gas) are subject to PM
and visible emissions limit standards. Steam generating units burning
gaseous fuels do not require a continuous opacity monitoring system
(COMS), but all other affected facilities burning liquid or solid fuels
are required to continuously monitor opacity. Opacity readings from the
COMS are not only used to determine compliance with the opacity
standard, but also serve as a continuous indicator of PM emission
levels. Elevated opacity levels are often indications of operating
problems with the PM control device and/or poor combustion.
    In general, the level of filterable PM emissions from oil-fired
steam generating units is a function of the completeness of fuel
combustion as well as the ash content in the oil. Distillate oil
contains negligible ash content, so the filterable PM emissions from
distillate oil-fired steam generating units are primarily comprised of
carbon particles resulting from incomplete combustion of the oil.
Residual oil contains larger amounts of ash (as much as 0.2 percent)
and additional PM results from the formation of coke, black smoke
(soot), and sulfates. Coke is comprised of larger particles and results
from poor atomization of the fuel; soot results from incomplete fuel
combustion. The larger coke particles comprise the majority of the mass
of PM emissions, but are not highly visible. Smaller black smoke
particles are comprised of fine particulate carbon and

have relatively little mass, but have maximum visibility (opacity)
impacts. Therefore, opacity for oil-fired steam generating units is not
always a reliable indicator of the total mass of PM emissions.
    Carbon monoxide (CO) emissions from oil-fired steam generating
units depend on the combustion efficiency of the fuel. The presence of
CO in the exhaust gases from an oil-fired steam generating unit results
principally from incomplete fuel combustion, and is an indicator of the
levels of both PM and organic compound emissions, and that a unit is
being operated improperly or not being well maintained. Furthermore,
the PM emissions from oil-fired steam generating units are related to
the sulfur content of the oil. Naturally low sulfur crude oil and
desulfurized oils are higher quality fuels and exhibit lower viscosity
and reduced asphaltene, ash, and sulfur content, which results in
better atomization and improved overall combustion properties.
    To provide additional flexibility and decrease the compliance
burden on affected facilities, EPA is requesting comments on whether
oil-fired steam generating units should be permitted to continuously
monitoring CO as an alternative to continuously monitoring opacity.
Many oil-fired steam generating units subject to subpart D are able to
achieve the PM emissions limit without the use of post-combustion PM
controls (e.g., electrostatic precipitator (ESP) or fabric filter). For
these units, opacity levels are primarily determined by the combustion
efficiency of the steam generating units. Since CO emissions are also a
direct function of the combustion efficiency, EPA has concluded that
either opacity or CO emissions can be used as reliable indicators of PM
emissions levels from oil-fired steam generating units not using PM or
CO post-combustion controls. Additionally, in situations where an oil-
fired steam generating unit is using a wet scrubber and opacity
monitoring using COMS is not feasible due to the water vapor in the gas
stream exiting the control device, continuous CO monitoring provides an
alternative means for monitoring PM emissions. The alternative would
not apply to oil-fired steam generating units using an ESP or fabric
filter for PM control or a CO catalyst to reduce CO emissions. Opacity
can be used by operators to identify problems with the PM control
equipment, and post-combustion PM and CO controls alter the
relationship between CO and PM emissions.
    If this alternative is added to subpart D, owners and operators of
affected oil-fired steam generating units without post-combustion
technologies to reduce PM, SO2, or CO (except a wet
scrubber) would be able to elect to install and operate a CO CEMS in
place of a COMS. The owner or operator would be required to
periodically review the CO emissions measurements from the CEMS. If the
CO emissions level exceeds a specified threshold or action level, the
owner or operator would need to initiate investigation of the relevant
combustion controls or equipment upon first discovery of the elevated
CO emissions incident and, if necessary, take corrective action to
adjust or repair the combustion controls or equipment to return the
steam generating unit operation to CO emissions levels below the action
level.
    To select a CO value for the action value, EPA reviewed CO
emissions data and CO emissions limits established by State air permits
and for existing oil-fired steam generating units. Based on this
review, EPA concluded that daily average CO emissions levels below 0.15
lb/MMBtu are representative of the levels of CO emissions achievable by
properly operated and maintained oil-fired steam generating units.
Thus, for this alternative EPA proposes to use a daily average CO
emissions level of 0.15 lb/MMBtu as the action level above which
corrective action would be required. EPA is requesting comment on
whether this is an appropriate level or whether a different level and/
or averaging time should be used.
    The fuel characteristics of distillate oil and low sulfur oils
result in inherently lower PM emissions. EPA is proposing the CO
monitoring alternative be restricted to only those steam generating
units burning distillate oil and residual oil that contains no more
than 0.30 percent sulfur. As another option, since distillate oil
containing no more than 0.05 weight percent sulfur (500 parts per
million (ppm) S) has relatively low emissions, should steam generating
units burning 500 ppm S distillate oil exclusively or in combination
with gaseous fuels be exempt from the COMS requirement, while all other
oil-fired facilities would still be required to install COMS?
    Finally, should the CO level of 0.15 lb/MMBtu be established as a
CO emissions limit or as a deviation that triggers corrective action?
If exceeding the CO level is a deviation requiring the owner or
operator to take corrective action, what percent of the time should an
affected source be allowed to exceed the CO action level before it is
considered a potential violation? As an alternative, since monitoring
CO provides equivalent or superior protection to the environment as
monitoring opacity, would it be appropriate to exempt oil-fired steam
generating units monitoring CO emissions from the opacity standard
completely? If oil-fired steam generating units were exempt from the
opacity standard, the CO level would be established as a CO emissions
limit and any exceedance above the level during operation would be a
potential violation. Draft language EPA is considering is available in
the docket.

B. Proposed Substantive Amendments to Subpart Da

1. Applicability
    EPA is proposing language to clarify the applicability of subpart
Da to electric utility steam generating units to clearly state the
intent of the amendments published on February 27, 2006. EPA is
revising 40 CFR 60.40Da to clarify that integrated gasification
combined cycle (IGCC) facilities are subject to subpart Da, and not the
stationary combustion turbine NSPS, subpart KKKK, 40 CFR part 60.
2. Compliance Procedures
    Compliance with the PM emissions limits in subpart Da is determined
by conducting performance tests, unless the owner or operator elects to
demonstrate compliance using PM CEMS. During the performance test, the
owner or operator also establishes opacity and appropriate control
device operating parameter limits based on the actual values measured
during the test. Following the performance test, the owner or operator
continuously monitors opacity and the selected operating parameters
with respect to the established limits. An owner or operator of an
affected steam generating unit using an ESP must monitor voltage and
secondary current; while affected sources using a fabric filter must
install and monitor bag leak detectors. If the threshold values are
exceeded, the owner or operator is required to perform a new
performance test to demonstrate that the affected source is still in
compliance with the applicable emissions limit.
    The PM not collected by an ESP and emitted in the ESP exhaust gas
stream has a relatively constant size distribution, which does not
change significantly as the ESP performance changes. Consequently, ESP
opacity variations from the baseline established during the performance
test reflect changes in PM mass emissions. For fabric filters, the
opacity and PM relationship is not as constant. An increase in PM
emissions from a fabric filter can occur from holes developing

in the bags. This results in a size distribution change of the
particles being emitted in the fabric filter exhaust gas stream. Since
the particles going through the holes are the same size distribution as
the inlet particles (not just the fine diameter particles that escape
capture and pass through the bag filter material) PM mass emissions
from a fabric filter can increase substantially with little impact on
opacity. For fabric filters, bag leak detectors are more sensitive to
increases in PM emissions than opacity.
    EPA is soliciting comment on whether opacity, in conjunction with
either monitoring ESP parameters or using fabric filter bag leak
detectors, are adequate and the appropriate monitoring parameters for
demonstrating continuous proper operation of the PM control device. If
not, what parameters should be monitored, and what percent deviation
from the baseline is appropriate? EPA is specifically asking if the 110
percent of the baseline opacity value measured during the performance
test is an appropriate indicator of the need for a new performance
test. Would it be appropriate to add a 5 percent allowable deviation
(on a 30-day rolling average) above the baseline opacity or set a lower
indicator limit of 5 percent per clock hour regardless of the opacity
value measured during the PM performance test? Since facilities using
fabric filters generally have low opacity emissions, an hourly opacity
limit of 5 percent would apply for them. In contrast, facilities using
ESP to control PM emissions tend to have higher opacity emissions, and
would still be able to establish a baseline opacity.
    To monitor the performance of an ESP, are voltage and secondary
current appropriate additional parameters to monitor, and is the 10
percent deviation from the baseline an appropriate amount of variation
to trigger a new performance test? As an alternative to establishing a
baseline voltage and secondary current, should daily use of an ESP
predictive performance computer model be required? One advantage of
using a predictive ESP model is that ESP performance is impacted by the
properties of the ash. Without using a model that accounts for both the
ash characteristics (amount and resistivity) and the ESP operating
parameters, voltage and secondary current cannot be directly correlated
to PM emissions. If use of a predictive ESP model was added, an
affected facility would be required to establish the model parameters
during each performance test and then use daily average ash
characteristics and ESP parameters to determine if a new performance
test has been triggered. Also, since ash characteristics vary
significantly even within the same coal type, EPA is considering
requiring that the baseline be re-determined (or model parameters
adjusted) each time the affected facility changes the ratio of fuels
used or takes delivery from a new coal mine or supplier. In addition,
to monitor the performance of a fabric filter, is a 5 percent bag leak
detector alarm rate on a 30-day rolling basis an appropriate trigger
for a performance test?
    EPA is also proposing to shorten the time period required to
conduct the ``triggered'' performance test from 60 days to 45 operating
days. Should the period be further shortened to 30 operating days from
the day of the initial exceedance, or is 60 operating days appropriate?
3. Alternate Carbon Monoxide Monitoring for Oil-Fired Steam Generating
Units
    One technical error EPA is correcting is the continuous opacity
monitoring requirements for oil-fired steam generating units subject to
subparts Da, Db, and Dc. Affected industrial, commercial, and
institutional steam generating units burning only low sulfur oil have
relatively low filterable particulate matter (PM) emissions and are
exempt from the PM standard, but still must continuously monitor
opacity. For these units, opacity serves both as an emissions limit on
visible emissions and as an indicator that the steam generating unit
and associated air pollution controls are being properly maintained and
operated. The intent of the amendments was to maintain the PM exemption
for affected facilities burning low sulfur oil and therefore not
require an initial PM performance test. It was not the intent of the
amendments to eliminate continuous opacity monitoring for these
facilities without first requesting public comment.
    Subpart Da requires all affected existing oil-fired steam
generating units to demonstrate compliance with the PM standard through
a performance test and installation of a COMS to monitor visible
emissions. Similar to subpart D, EPA is requesting comment on whether
affected steam generating units burning distillate oil containing less
than 0.05 weight percent sulfur (500 ppm S) should be exempt from the
COMS requirement. As an alternative, should EPA permit low sulfur oil-
fired subpart Da affected facilities without PM, SO2, or CO
post-combustion controls (except a wet scrubber) to be allowed to use
the same CO monitoring alternative for steam generating units subject
to subpart D as discussed in Section A.3 of this notice instead of
using a COMS? If EPA adopts this provision, the affected source using a
CO CEMS in place of a COMS would be subject to the same daily CO action
level of 0.15 lb/MMBtu as would be applied to affected sources subject
to subpart D. Similar to units with PM CEMS, the 20 percent opacity
standard would still apply to the source, but opacity would not be
required to be continuously monitored. Since residual oil-fired steam
generating units generally require post-combustion controls to achieve
the PM standard in subpart Da, in practice EPA would expect that only
owners and operators of distillate oil-fired units and residual oil-
fired units using wet scrubbers would elect to use this alternative.
4. Alternative PM CEMS Monitoring
    For owners and operators of affected electric utility steam
generating units electing to use PM CEMS to demonstrate continuous
compliance with the applicable PM emissions limit, EPA is proposing a
phased data availability requirement. Initially, PM CEMS hourly
averages would be required to be obtained for a minimum of 75 percent
of all operating hours on a 30-day rolling average basis. Beginning on
January 1, 2012, valid PM CEMS hourly averages would be required for a
minimum of 90 percent of all operating hours on a 30-day rolling
average basis; this value is consistent with the recently amended 90
percent data availability requirement in subpart Da for NOX
and SO2 CEMS.
    EPA is also requesting comments on the proper emissions averaging
time for units electing to use PM CEMS. EPA is proposing to maintain
that PM emissions be averaged over each operating day, but is
requesting comments on whether, alternatively, this average should be
on an 8-hour, 24-hour, 30-day, or other appropriate rolling average
period. Longer averaging times allow for more stable emission rates and
tend toward a lower standard. Shorter averaging times introduce more
variability in emission rates and tend toward higher standards. EPA
requests that each commenter provide an appropriate emission standard
for use with any suggested alternate averaging time.

C. Proposed Substantive Amendments to Subpart Db

1. Emissions Standards
    EPA is proposing that steam generating units subject to subpart Db
that burn natural gas or coke oven gas

(COG) be exempt from the PM emissions standard. Both natural gas and
COG-fired steam generating units do not use post-combustion PM
controls, and have inherently low PM emissions. As a result, the PM
performance test results in limited environmental benefit.
    EPA is also proposing to revise the procedure used to grant site-
specific NOX limits under 40 CFR 60.44b. Only a limited
number of site-specific limits have been granted under this provision
in the past 20 years. Currently, EPA amends subpart Db by a formal
notice and comment rulemaking when granting a site-specific limit. To
simplify the procedure and reduce administrative burden, EPA is
proposing to grant site-specific NOX limits by sending a
letter to the facility owner or operator detailing the site-specific
limit and publishing that letter in EPA's applicability determination
index.
2. Units Burning Coke Oven Gas
    Because of the specific characteristics of the steel industry, EPA
is proposing to allow a 30-day exceedance per year from the
SO2 emission limit for steam generating units burning COG
exclusively or in combination with other gaseous fuels or distillate
oil. COG desulfurization facilities require periodic maintenance, but
the coking process continues during this time, and it is cost
prohibitive to store the COG. Coke-making facilities would either have
to install a second desulfurization unit or flare the COG and burn
natural gas during the maintenance period. Of these two options, the
least cost option would be to flare the COG and use natural gas during
the annual maintenance. This would result in both increased cost to the
steel industry and NOX emissions without achieving any
reductions in SO2. State permitting authorities have
recognized this and have included similar exemptions in their permits.
3. Compliance Procedures
    EPA is proposing to amend 40 CFR 60.49b(r) to add a detailed
procedure for affected facilities complying with the fuel based limit.
4. Alternate Opacity Monitoring
    Since COG-fired steam generating units have filterable PM emissions
similar to natural gas, EPA is proposing to exempt industrial-
commercial-institutional steam generating units burning COG from the
COM requirement.
    Under subpart Db, 40 CFR part 60, affected facilities burning coal
(except COG), wood, and oil (other than very low sulfur oil) are
subject to the PM standard. All coal (except COG), wood, and oil-fired
affected facilities are subject to the opacity standard, and are
required to install a COMS. Consistent with the CO monitoring
alternative for steam generating units subject to subparts D or Da as
discussed in Section A.3 of this notice, EPA is proposing to exempt
affected industrial-commercial-institutional steam generating units not
using post-combustion technology to reduce SO2 or PM
emissions and burning only distillate oil containing no greater than
0.05 weight percent (500 ppm) sulfur and low sulfur gasified fuels
(desulfurized gasified coal and gasified wood) from the COMS
requirements in subpart Db. The filterable PM emissions from sources
burning low sulfur distillate are inherently low (less than 0.02 lb/
MMBtu), and this change would provide flexibility for natural gas-fired
steam generating units to burn distillate oil as a backup fuel without
having to install and operate a COMS. As an alternative, should EPA
permit low sulfur (less than 0.30 weight percent sulfur) affected oil-
fired units not using post-combustion technology (except a wet
scrubber) to reduce emissions of SO2, PM, or CO to install a
CO CEMS in place of a COMS? EPA is considering using the same daily CO
action level of 0.15 lb/MMBtu as would be applied to affected sources
subject to subpart D or Da. The industrial boiler MACT requires new
oil-fired units to monitor CO; allowing this alternate monitoring would
reduce the burden on the regulated community while still providing
adequate environmental protection.

D. Proposed Substantive Amendments to Subpart Dc

1. Emissions Standards
    EPA is proposing that industrial-commercial-institutional steam
generating units subject to subpart Dc that burn natural gas or low-
sulfur oil be exempt from the PM emissions standard. This amendment
reflects EPA's intent for applying the PM emissions limits to
industrial-commercial-institutional steam generating units subject to
subpart Dc, and would be consistent with the exemption from the PM
emissions limits allowed for units subject to Dc that were constructed
before February 28, 2005.
2. Compliance Procedures
    EPA is proposing to clarify the fuel recordkeeping requirements in
40 CFR 60.48c(g). Owners or operators of steam generating units
combusting only natural gas, wood, and distillate oil containing less
than 0.5 weight percent sulfur may elect to record fuel usage amounts
on a monthly instead of daily basis. In addition, owners or operators
of steam generating units with maximum heat input capacities of less
than 30 MMBtu/hr and combusting coal and residual oil may elect to
record the amounts of fuels combusted each calendar month. EPA has
concluded that allowing monthly fuel usage monitoring for these steam
generating units provides adequate assurance of compliance, as well as
minimizing the burden to affected facilities.
    EPA is considering and requesting comments on whether owners or
operators of multiple steam generating units located on a contiguous
property facility where the only fuels combusted in any steam
generating unit located on that property are natural gas, wood, and
distillate oil containing no more than 0.50 weight percent sulfur
should have the option to elect to only record the total amounts of
fuels delivered to the property each calendar month instead of the
amount combusted at each affected facility. Draft language EPA is
requesting comment on for a potential 40 CFR 60.48c(g)(3) is as
follows:
    ``(3) As an alternative to meeting the requirements of paragraph
(g)(1) of this section, the owner or operator of an affected facility
or multiple affected facilities located on a contiguous property unit
where the only fuels combusted in any steam generating unit (including
steam generating units not subject to this subpart) at that property
are natural gas, wood, distillate oil meeting the most current
requirements in Sec.  60.42c to use fuel certification to demonstrate
compliance with the SO2 standard, and/or fuels, excluding
coal and residual oil, not subject to an emissions standard (excluding
opacity) may elect to record and maintain records of the total amount
of each steam generating unit fuel delivered to that property during
each calendar month.''
    This alternative would be restricted to properties where no coal or
residual oil is combusted in any steam generating unit located at that
property. In addition, the alternative would require that all
distillate oil-fired steam generating units located on the property
(including those not subject to subpart Dc) only combust distillate oil
containing no more than 0.50 weight percent sulfur. If subpart Dc is
amended in the future to require the use of lower sulfur distillate
oil, all steam generating units located at that property would have to
switch to the lower sulfur distillate oil for the owner or operator to
elect to use this alternative.

3. Alternate Opacity Monitoring
    Under subpart Dc, 40 CFR part 60, affected steam generating units
burning coal, wood, and oil containing more than 0.5 weight percent
sulfur are subject to the PM standard. All coal, wood, and oil-fired
affected facilities are subject to the opacity standard, but affected
facilities burning distillate oil containing less than 0.5 weight
percent sulfur are exempt from the COM requirement. EPA is proposing
that owners and operators of affected steam generating units burning
desulfurized gasified coal and gasified wood and not using post-
combustion PM or SO2 controls be exempt from continuously
monitoring opacity. Should the exemption be limited to fuels with
potential SO2 emissions less than 26 nanograms per Joule
heat input (0.06 lb/MMBtu), or should a different potential sulfur
limit be required? Sources supporting this exemption should provide
emissions data demonstrating that uncontrolled PM emissions are
consistently below 0.030 lb/MMBtu. These facilities would still be
subject to the PM emission limit and opacity standard, but exempt from
the COMS requirement.
    Finally, should affected steam generating units burning residual
oil containing less than 0.5 weight percent sulfur and/or desulfurized
gasified coal and gasified wood have the option of monitoring CO
emissions in place of opacity consistent with the CO monitoring
alternative for steam generating units subject to subpart D as
discussed in Section A.3 of this notice? EPA is requesting comment on
whether residual oil-fired steam generating units subject to subpart Dc
should be able to elect to install a CO CEMS and maintain daily average
CO emission below a level of 0.15 lb/MMBtu in place of the COMS
requirement. This would reduce the compliance burden for sources
already monitoring CO emissions (due to the boiler MACT or other
regulation) and still provide adequate environmental protection.

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    This action is not a ``significant regulatory action'' under the
terms of Executive Order (EO) 12866 (58 FR 51735, October 4, 1993) and
is, therefore, not subject to review under the EO. EPA has concluded
that the amendments EPA is requesting additional comments on will not
change the costs or benefits of the rule.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden
under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et
seq. The proposed amendments result in no changes to the information
collection requirements of the existing standards of performance and
would have no impact on the information collection estimate of
projected cost and hour burden made and approved by the Office of
Management and Budget (OMB) during the development of the existing
standards of performance. Therefore, the information collection
requests have not been amended. 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). 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.
    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. 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 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 proposed amendments on
small entities, small entity is defined as: (1) A small business as
defined by the Small Business Administration's regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
    After considering the economic impacts of this proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities.
    Although this proposed rule will not have a significant economic
impact on a substantial number of small entities, EPA nonetheless has
tried to reduce the impact of this rule on small entities. EPA is
proposing to reduce the fuel usage recordkeeping requirement for
subpart Dc facilities. In addition, EPA is taking comment on minimizing
the continuous opacity monitoring requirements for oil-fired
facilities. EPA has, therefore, concluded that this proposed rule will
relieve regulatory burden for all affected small entities. EPA
continues to be interested in the potential impacts of the proposed
rule on small entities and welcome comments on issues related to such
impacts.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 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 to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million

or more in any one 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 the Administrator 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, it
must have developed under section 203 of the UMRA a small government
agency plan. 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 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 proposed amendments will 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 proposed amendments are not
subject to the requirements of section 202 and 205 of the UMRA. In
addition, EPA determined that the proposed amendments contain no
regulatory requirements that might significantly or uniquely affect
small governments because the burden is small and the regulation does
not unfairly apply to small governments. Therefore, the proposed
amendments are not subject to the requirements of section 203 of the
UMRA.

E. Executive Order 13132: Federalism

    Executive Order 13132, entitled ``Federalism'' (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 proposed amendments do not have federalism implications. They
will not have substantial direct effects on the States, on the
relationship between the national government and the States, or on the
distribution of power and responsibilities among the various levels of
government, as specified in Executive Order 13132. The proposed
amendments will not impose substantial direct compliance costs on State
or local governments; it will not preempt State law. Thus, Executive
Order 13132 does not apply to the proposed amendments.

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

    Executive Order 13175, entitled ``Consultation and Coordination
with Indian Tribal Governments'' (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.'' The proposed amendments do
not have tribal implications, as specified in Executive Order 13175.
The proposed amendments 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. Thus, Executive Order
13175 does not apply to the proposed amendments.

G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks

    Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any
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, the Agency must evaluate the environmental health or
safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency.
    This proposed action is not subject to the Executive Order because
it is not economically significant as defined under Executive Order
12866, and because EPA interprets Executive Order 13045 as applying
only to those regulatory actions that are based on health or safety
risks, such that the analysis required under section 5-501 of the Order
has the potential to influence the regulation. The proposed amendments
are based on technology performance and not on health or safety risks
and, therefore, are not subject to Executive Order 13045.

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

    This proposed action is not subject to Executive Order 13211,
``Actions Concerning Regulations That Significantly Affect Energy
Supply, Distribution, or Use'' (66 FR 28355, May 22, 2001) because it
is not a significant regulatory action under Executive Order 12866.

I. National Technology Transfer Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113, Section 12(d) (15 U.S.C. 272
note) directs us to use voluntary consensus standards in our regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., material specifications, test methods, sampling
procedures, business practices) developed or adopted by one or more
voluntary consensus bodies. The NTTAA directs us to provide Congress,
through OMB, explanations when EPA decides not use available and
applicable voluntary consensus standards.
    This action does not involve any new technical standards or the
incorporation by reference of existing technical standards. Therefore,
the consideration of voluntary consensus standards is not relevant to
this action.

List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.

    Dated: January 31, 2007.
Stephen L. Johnson,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part
60, of the Code of the Federal Regulations is proposed to be amended as
follows:

PART 60--[AMENDED]

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

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

Subpart A--[Amended]

    2. Section 60.17 is amended by revising paragraph (a) to read as
follows:

Sec.  60.17  Incorporation by Reference

* * * * *
    (a) The following materials are available for purchase from at
least one of the following addresses: American Society for Testing and
Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West
Conshohocken, PA 19428-2959; or ProQuest, 300 North Zeeb Road, Ann
Arbor, MI 48106.
    (1) ASTM A99-76, 82 (Reapproved 1987), Standard Specification for
Ferromanganese, incorporation by reference (IBR) approved for Sec.
60.261.
    (2) ASTM A100-69, 74, 93, Standard Specification for Ferrosilicon,
IBR approved for Sec.  60.261.
    (3) ASTM A101-73, 93, Standard Specification for Ferrochromium, IBR
approved for Sec.  60.261.
    (4) ASTM A482-76, 93, Standard Specification for
Ferrochromesilicon, IBR approved for Sec.  60.261.
    (5) ASTM A483-64, 74 (Reapproved 1988), Standard Specification for
Silicomanganese, IBR approved for Sec.  60.261.
    (6) ASTM A495-76, 94, Standard Specification for Calcium-Silicon
and Calcium Manganese-Silicon, IBR approved for Sec.  60.261.
    (7) ASTM D86-78, 82, 90, 93, 95, 96, Distillation of Petroleum
Products, IBR approved for Sec. Sec.  60.562-2(d), 60.593(d), and
60.633(h).
    (8) ASTM D129-64, 78, 95, 00, Standard Test Method for Sulfur in
Petroleum Products (General Bomb Method), IBR approved for Sec. Sec.
60.106(j)(2), 60.335(b)(10)(i), and Appendix A: Method 19, <IP_ADDRESS>.3.
    (9) ASTM D129-00 (Reapproved 2005), Standard Test Method for Sulfur
in Petroleum Products (General Bomb Method), IBR approved for Sec.
60.4415(a)(1)(i).
    (10) ASTM D240-92, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for Sec.
60.46(c).
    (11) ASTM D240-76, 92, Standard Test Method for Heat of Combustion
of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for Sec.
60.296(b) and Appendix A: Method 19, Section <IP_ADDRESS>.3.
    (12) ASTM D270-65, 75, Standard Method of Sampling Petroleum and
Petroleum Products, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.1.
    (13) ASTM D323-82, 94, Test Method for Vapor Pressure of Petroleum
Products (Reid Method), IBR approved for Sec. Sec.  60.111(l),
60.111a(g), 60.111b(g), and 60.116b(f)(2)(ii).
    (14) ASTM D388-99 (Reapproved 2004) [egr] \1\, Standard
Specification for Classification of Coals by Rank, IBR approved for
Sec. Sec.  60.41(g) of subpart D of this part, 60.45(f)(4)(i),
60.45(f)(4)(ii), 60.45(f)(4)(vi), 60.41Da of subpart Da of this part,
and 60.41b of subpart Db of this part, 60.41c of subpart Dc of this
part.
    (15) ASTM D388-77, 90, 91, 95, 98a, Standard Specification for
Classification of Coals by Rank, IBR approved for 60.251(b) and (c) of
subpart Y of this part.
    (16) ASTM D388-77, 90, 91, 95, 98a, 99 (Reapproved 2004) [egr] \1\,
Standard Specification for Classification of Coals by Rank, IBR
approved for Sec. Sec.  60.24(h)(8), and 60.4102.
    (17) ASTM D396-98, Standard Specification for Fuel Oils, IBR
approved for Sec. Sec.  60.41b of subpart Db of this part and 60.41c of
subpart Dc of this part.
    (18) ASTM D396-78, 89, 90, 92, 96, 98, Standard Specification for
Fuel Oils, IBR approved for 60.111(b) of subpart K of this part and
60.111a(b) of subpart Ka of this part.
    (19) ASTM D975-78, 96, 98a, Standard Specification for Diesel Fuel
Oils, IBR approved for Sec. Sec.  60.111(b) of subpart K of this part
and 60.111a(b) of subpart Ka of this part.
    (20) ASTM D1072-80, 90 (Reapproved 1994), Standard Test Method for
Total Sulfur in Fuel Gases, IBR approved for Sec.  60.335(b)(10)(ii).
    (21) ASTM D1072-90 (Reapproved 1999), Standard Test Method for
Total Sulfur in Fuel Gases, IBR approved for Sec.  60.4415(a)(1)(ii).
    (22) ASTM D1137-75, Standard Method for Analysis of Natural Gases
and Related Types of Gaseous Mixtures by the Mass Spectrometer, IBR
approved for Sec.  60.45(f)(5)(i).
    (23) ASTM D1193-77, 91, Standard Specification for Reagent Water,
IBR approved for Appendix A: Method 5, Section 7.1.3; Method 5E,
Section 7.2.1; Method 5F, Section 7.2.1; Method 6, Section 7.1.1;
Method 7, Section 7.1.1; Method 7C, Section 7.1.1; Method 7D, Section
7.1.1; Method 10A, Section 7.1.1; Method 11, Section 7.1.3; Method 12,
Section 7.1.3; Method 13A, Section 7.1.2; Method 26, Section 7.1.2;
Method 26A, Section 7.1.2; and Method 29, Section 7.2.2.
    (24) ASTM D1266-87, 91, 98, Standard Test Method for Sulfur in
Petroleum Products (Lamp Method), IBR approved for Sec. Sec.
60.106(j)(2) and 60.335(b)(10)(i).
    (25) ASTM D1266-98 (Reapproved 2003) [egr] \1\, Standard Test
Method for Sulfur in Petroleum Products (Lamp Method), IBR approved for
Sec.  60.4415(a)(1)(i).
    (26) ASTM D1475-60 (Reapproved 1980), 90, Standard Test Method for
Density of Paint, Varnish Lacquer, and Related Products, IBR approved
for Sec.  60.435(d)(1), Appendix A: Method 24, Section 6.1; and Method
24A, Sections 6.5 and 7.1.
    (27) ASTM D1552-83, 95, 01, Standard Test Method for Sulfur in
Petroleum Products (High-Temperature Method), IBR approved for
Sec. Sec.  60.106(j)(2), 60.335(b)(10)(i), and Appendix A: Method 19,
Section <IP_ADDRESS>.3.
    (28) ASTM D1552-03, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method), IBR approved for Sec.
60.4415(a)(1)(i).
    (29) ASTM D1826-94, Standard Test Method for Calorific Value of
Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR
approved for Sec. Sec.  60.45(f)(5)(ii) and 60.46(c)(2).
    (30) ASTM D1826-77, 94, Standard Test Method for Calorific Value of
Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR
approved for Sec.  60.296(b)(3) and Appendix A: Method 19, Section
<IP_ADDRESS>.
    (31) ASTM D1835-03a, Standard Specification for Liquefied Petroleum
(LP) Gases, IBR approved for Sec.  60.41Da of subpart Da of this part,
60.41b of subpart Db of this part, and 60.41c of subpart Dc of this
part.
    (32) ASTM D1945-96, Standard Method for Analysis of Natural Gas by
Gas Chromatography, IBR approved for Sec.  60.45(f)(5)(i).
    (33) ASTM D1946-77, 90 (Reapproved 1994), Standard Method for
Analysis of Reformed Gas by Gas Chromatography, IBR approved for
Sec. Sec.  60.18(f)(3), 60.564(f)(1), 60.614(e)(2)(ii), 60.614(e)(4),
60.664(e)(2)(ii), 60.664(e)(4), 60.704(d)(2)(ii), and 60.704(d)(4).
    (34) ASTM D1946-90 (Reapproved 1994), Standard Method for Analysis
of Reformed Gas by Gas Chromatography, IBR approved for Sec.
60.45(f)(5)(i).
    (35) ASTM D2013-72, 86, Standard Method of Preparing Coal Samples
for Analysis, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.3.
    (36) ASTM D2015-96, Standard Test Method for Gross Calorific Value
of Solid Fuel by the Adiabatic Bomb Calorimeter, IBR approved for
Sec. Sec.  60.45(f)(5)(ii) and 60.46(c)(2).
    (37) ASTM D2015-77 (Reapproved 1978), 96, Standard Test Method for
Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter,
IBR

approved for Appendix A: Method 19, Section <IP_ADDRESS>.3.
    (38) ASTM D2016-74, 83, Standard Test Methods for Moisture Content
of Wood, IBR approved for Appendix A: Method 28, Section 16.1.1.
    (39) ASTM D2234-76, 96, 97b, 98, Standard Methods for Collection of
a Gross Sample of Coal, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.1.
    (40) ASTM D2369-81, 87, 90, 92, 93, 95, Standard Test Method for
Volatile Content of Coatings, IBR approved for Appendix A: Method 24,
Section 6.2.
    (41) ASTM D2382-76, 88, Heat of Combustion of Hydrocarbon Fuels by
Bomb Calorimeter (High-Precision Method), IBR approved for Sec. Sec.
60.18(f)(3), 60.485(g)(6), 60.564(f)(3), 60.614(e)(4), 60.664(e)(4),
and 60.704(d)(4).
    (42) ASTM D2504-67, 77, 88 (Reapproved 1993), Noncondensable Gases
in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR
approved for Sec.  60.485(g)(5).
    (43) ASTM D2584-68 (Reapproved 1985), 94, Standard Test Method for
Ignition Loss of Cured Reinforced Resins, IBR approved for Sec.
60.685(c)(3)(i).
    (44) ASTM D2597-94 (Reapproved 1999), Standard Test Method for
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing
Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for
Sec.  60.335(b)(9)(i).
    (45) ASTM D2622-87, 94, 98, Standard Test Method for Sulfur in
Petroleum Products by Wavelength Dispersive X-Ray Fluorescence
Spectrometry,'' IBR approved for Sec. Sec.  60.106(j)(2) and
60.335(b)(10)(i).
    (46) ASTM D2622-05, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry,''
IBR approved for Sec.  60.4415(a)(1)(i).
    (47) ASTM D2879-83, 96, 97, Test Method for Vapor Pressure-
Temperature Relationship and Initial Decomposition Temperature of
Liquids by Isoteniscope, IBR approved for Sec. Sec.  60.111b(f)(3),
60.116b(e)(3)(ii), 60.116b(f)(2)(i), and 60.485(e)(1).
    (48) ASTM D2880-78, 96, Standard Specification for Gas Turbine Fuel
Oils, IBR approved for Sec. Sec.  60.111(b), 60.111a(b), and 60.335(d).
    (49) ASTM D2908-74, 91, Standard Practice for Measuring Volatile
Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR
approved for Sec.  60.564(j).
    (50) ASTM D2986-71, 78, 95a, Standard Method for Evaluation of Air,
Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR
approved for Appendix A: Method 5, Section 7.1.1; Method 12, Section
7.1.1; and Method 13A, Section <IP_ADDRESS>.
    (51) ASTM D3173-73, 87, Standard Test Method for Moisture in the
Analysis Sample of Coal and Coke, IBR approved for Appendix A: Method
19, Section <IP_ADDRESS>.3.
    (52) ASTM D3176-89, Standard Method for Ultimate Analysis of Coal
and Coke, IBR approved for Sec.  60.45(f)(5)(i).
    (53) ASTM D3176-74, 89, Standard Method for Ultimate Analysis of
Coal and Coke, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.
    (54) ASTM D3177-75, 89, Standard Test Method for Total Sulfur in
the Analysis Sample of Coal and Coke, IBR approved for Appendix A:
Method 19, Section <IP_ADDRESS>.3.
    (55) ASTM D3178-89, Standard Test Methods for Carbon and Hydrogen
in the Analysis Sample of Coal and Coke, IBR approved for Sec.
60.45(f)(5)(i).
    (56) ASTM D3246-81, 92, 96, Standard Test Method for Sulfur in
Petroleum Gas by Oxidative Microcoulometry, IBR approved for Sec.
60.335(b)(10)(ii).
    (57) ASTM D3246-05, Standard Test Method for Sulfur in Petroleum
Gas by Oxidative Microcoulometry, IBR approved for Sec.
60.4415(a)(1)(ii).
    (58) ASTM D3270-73T, 80, 91, 95, Standard Test Methods for Analysis
for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated
Method), IBR approved for Appendix A: Method 13A, Section 16.1.
    (59) ASTM D3286-85, 96, Standard Test Method for Gross Calorific
Value of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved
for Appendix A: Method 19, Section <IP_ADDRESS>.3.
    (60) ASTM D3370-76, 95a, Standard Practices for Sampling Water, IBR
approved for Sec.  60.564(j).
    (61) ASTM D3792-79, 91, Standard Test Method for Water Content of
Water-Reducible Paints by Direct Injection into a Gas Chromatograph,
IBR approved for Appendix A: Method 24, Section 6.3.
    (62) ASTM D4017-81, 90, 96a, Standard Test Method for Water in
Paints and Paint Materials by the Karl Fischer Titration Method, IBR
approved for Appendix A: Method 24, Section 6.4.
    (63) ASTM D4057-81, 95, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products, IBR approved for Appendix A: Method
19, Section <IP_ADDRESS>.3.
    (64) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual
Sampling of Petroleum and Petroleum Products, IBR approved for Sec.
60.4415(a)(1).
    (65) ASTM D4084-82, 94, Standard Test Method for Analysis of
Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method),
IBR approved for Sec.  60.334(h)(1).
    (66) ASTM D4084-05, Standard Test Method for Analysis of Hydrogen
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR
approved for Sec. Sec.  60.4360 and 60.4415(a)(1)(ii).
    (67) ASTM D4177-95, Standard Practice for Automatic Sampling of
Petroleum and Petroleum Products, IBR approved for Appendix A: Method
19, Section <IP_ADDRESS>.1.
    (68) ASTM D4177-95 (Reapproved 2000), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products, IBR approved
for Sec.  60.4415(a)(1).
    (69) ASTM D4239-85, 94, 97, Standard Test Methods for Sulfur in the
Analysis Sample of Coal and Coke Using High Temperature Tube Furnace
Combustion Methods, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.3.
    (70) ASTM D4294-02, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec.  60.335(b)(10)(i).
    (71) ASTM D4294-03, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec.  60.4415(a)(1)(i).
    (72) ASTM D4442-84, 92, Standard Test Methods for Direct Moisture
Content Measurement in Wood and Wood-base Materials, IBR approved for
Appendix A: Method 28, Section 16.1.1.
    (73) ASTM D4444-92, Standard Test Methods for Use and Calibration
of Hand-Held Moisture Meters, IBR approved for Appendix A: Method 28,
Section 16.1.1.
    (74) ASTM D4457-85 (Reapproved 1991), Test Method for Determination
of Dichloromethane and 1, 1, 1-Trichloroethane in Paints and Coatings
by Direct Injection into a Gas Chromatograph, IBR approved for Appendix
A: Method 24, Section 6.5.
    (75) ASTM D4468-85 (Reapproved 2000), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry, IBR approved for Sec. Sec.  60.335(b)(10)(ii) and
60.4415(a)(1)(ii).
    (76) ASTM D4629-02, Standard Test Method for Trace Nitrogen in
Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and
Chemiluminescence Detection, IBR

approved for Sec. Sec.  60.49b(e) and 60.335(b)(9)(i).
    (77) ASTM D4809-95, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR
approved for Sec. Sec.  60.18(f)(3), 60.485(g)(6), 60.564(f)(3),
60.614(d)(4), 60.664(e)(4), and 60.704(d)(4).
    (78) ASTM D4810-88 (Reapproved 1999), Standard Test Method for
Hydrogen Sulfide in Natural Gas Using Length of Stain Detector Tubes,
IBR approved for Sec. Sec.  60.4360 and 60.4415(a)(1)(ii).
    (79) ASTM D5287-97 (Reapproved 2002), Standard Practice for
Automatic Sampling of Gaseous Fuels, IBR approved for Sec.
60.4415(a)(1).
    (80) ASTM D5403-93, Standard Test Methods for Volatile Content of
Radiation Curable Materials, IBR approved for Appendix A: Method 24,
Section 6.6.
    (81) ASTM D5453-00, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec.  60.335(b)(10)(i).
    (82) ASTM D5453-05, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec.  60.4415(a)(1)(i).
    (83) ASTM D5504-01, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence, IBR approved for Sec. Sec.  60.334(h)(1) and
60.4360.
    (84) ASTM D5762-02, Standard Test Method for Nitrogen in Petroleum
and Petroleum Products by Boat-Inlet Chemiluminescence, IBR approved
for Sec.  60.335(b)(9)(i).
    (85) ASTM D5865-98, Standard Test Method for Gross Calorific Value
of Coal and Coke, IBR approved for Sec.  60.45(f)(5)(ii), 60.46(c)(2),
and Appendix A: Method 19, Section <IP_ADDRESS>.3.
    (86) ASTM D6216-98, Standard Practice for Opacity Monitor
Manufacturers to Certify Conformance with Design and Performance
Specifications, IBR approved for Appendix B, Performance Specification
1.
    (87) ASTM D6228-98, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Flame Photometric Detection, IBR approved for Sec.  60.334(h)(1).
    (88) ASTM D6228-98 (Reapproved 2003), Standard Test Method for
Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by
Gas Chromatography and Flame Photometric Detection, IBR approved for
Sec. Sec.  60.4360 and 60.4415.
    (89) ASTM D6348-03, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy, IBR approved for table 7 of Subpart IIII
of this part.
    (90) ASTM D6366-99, Standard Test Method for Total Trace Nitrogen
and Its Derivatives in Liquid Aromatic Hydrocarbons by Oxidative
Combustion and Electrochemical Detection, IBR approved for Sec.
60.335(b)(9)(i).
    (91) ASTM D6522-00, Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in
Emissions from Natural Gas-Fired Reciprocating Engines, Combustion
Turbines, Boilers, and Process Heaters Using Portable Analyzers, IBR
approved for Sec.  60.335(a).
    (92) ASTM D6667-01, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases
by Ultraviolet Fluorescence, IBR approved for Sec.  60.335(b)(10)(ii).
    (93) ASTM D6667-04, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases
by Ultraviolet Fluorescence, IBR approved for Sec.  60.4415(a)(1)(ii).
    (94) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method), IBR approved for Appendix B
to part 60, Performance Specification 12A, Section 8.6.2.
    (95) ASTM E168-67, 77, 92, General Techniques of Infrared
Quantitative Analysis, IBR approved for Sec. Sec.  60.593(b)(2) and
60.632(f).
    (96) ASTM E169-63, 77, 93, General Techniques of Ultraviolet
Quantitative Analysis, IBR approved for Sec. Sec.  60.593(b)(2) and
60.632(f).
    (97) ASTM E260-73, 91, 96, General Gas Chromatography Procedures,
IBR approved for Sec. Sec.  60.593(b)(2) and 60.632(f).
* * * * *

Subpart D--[Amended]

    3. Part 60 is amended by revising subpart D to read as follows:
Subpart D--Standards of Performance for Fossil-Fuel-Fired Steam
Generators for Which Construction is Commenced After August 17, 1971
Sec.
60.40 Applicability and designation of affected facility.
60.41 Definitions.
60.42 Standard for particulate matter (PM).
60.43 Standard for sulfur dioxide (SO2).
60.44 Standard for nitrogen oxides (NOX).
60.45 Emission and fuel monitoring.
60.46 Test methods and procedures.

Subpart D--Standards of Performance for Fossil-Fuel-Fired Steam
Generators for Which Construction Is Commenced After August 17,
1971

Sec.  60.40  Applicability and designation of affected facility.

    (a) The affected facilities to which the provisions of this subpart
apply are:
    (1) Each fossil-fuel-fired steam generating unit of more than 73
megawatts (MW) heat input rate (250 million British thermal units per
hour (MMBtu/hr)).
    (2) Each fossil-fuel and wood-residue-fired steam generating unit
capable of firing fossil fuel at a heat input rate of more than 73 MW
(250 MMBtu/hr).
    (b) Any change to an existing fossil-fuel-fired steam generating
unit to accommodate the use of combustible materials, other than fossil
fuels as defined in this subpart, shall not bring that unit under the
applicability of this subpart.
    (c) Except as provided in paragraph (d) of this section, any
facility under paragraph (a) of this section that commenced
construction or modification after August 17, 1971, is subject to the
requirements of this subpart.
    (d) The requirements of Sec. Sec.  60.44 (a)(4), (a)(5), (b) and
(d), and 60.45(f)(4)(vi) are applicable to lignite-fired steam
generating units that commenced construction or modification after
December 22, 1976.
    (e) Any facility covered under subpart Da is not covered under this
subpart.

Sec.  60.41  Definitions.

    As used in this subpart, all terms not defined herein shall have
the meaning given them in the Act, and in subpart A of this part.
    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.
    Fossil-fuel fired steam generating unit means a furnace or boiler
used in the process of burning fossil fuel for the purpose of producing
steam by heat transfer.
    Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such materials for the
purpose of creating useful heat.

    Coal refuse means waste-products of coal mining, cleaning, and coal
preparation operations (e.g. culm, gob, etc.) containing coal, matrix
material, clay, and other organic and inorganic material.
    Fossil fuel and wood residue-fired steam generating unit means a
furnace or boiler used in the process of burning fossil fuel and wood
residue for the purpose of producing steam by heat transfer.
    Wood residue means bark, sawdust, slabs, chips, shavings, mill
trim, and other wood products derived from wood processing and forest
management operations.
    Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by ASTM D388 (incorporated by reference, see
Sec.  60.17).

Sec.  60.42  Standard for particulate matter (PM).

    (a) On and after the date on which the performance test required to
be conducted by 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 any gases that:
    (1) Contain PM in excess of 43 nanograms per joule (ng/J) heat
input (0.10 lb/MMBtu) derived from fossil fuel or fossil fuel and wood
residue.
    (2) Exhibit greater than 20 percent opacity except for one six-
minute period per hour of not more than 27 percent opacity.
    (b)(1) On or after December 28, 1979, no owner or operator shall
cause to be discharged into the atmosphere from the Southwestern Public
Service Company's Harrington Station 1, in Amarillo, TX, any
gases which exhibit greater than 35 percent opacity, except that a
maximum of 42 percent opacity shall be permitted for not more than 6
minutes in any hour.
    (2) Interstate Power Company shall not cause to be discharged into
the atmosphere from its Lansing Station Unit No. 4 in Lansing, IA, any
gases which exhibit greater than 32 percent opacity, except that a
maximum of 39 percent opacity shall be permitted for not more than six
minutes in any hour.

Sec.  60.43  Standard for sulfur dioxide (SO2).

    (a) On and after the date on which the performance test required to
be conducted by 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 any gases that contain
SO2 in excess of:
    (1) 340 ng/J heat input (0.80 lb/MMBtu) derived from liquid fossil
fuel or liquid fossil fuel and wood residue.
    (2) 520 ng/J heat input (1.2 lb/MMBtu) derived from solid fossil
fuel or solid fossil fuel and wood residue, except as provided in
paragraph (e) of this section.
    (b) When different fossil fuels are burned simultaneously in any
combination, the applicable standard (in ng/J) shall be determined by
proration using the following formula:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.000

Where:

PSSO2 = Prorated standard for SO2 when burning
different fuels simultaneously, in ng/J heat input derived from all
fossil fuels;
y = Percentage of total heat input derived from liquid fossil; and
z = Percentage of total heat input derived from solid fossil fuel.

    (c) Compliance shall be based on the total heat input from all
fossil fuels burned, including gaseous fuels.
    (d) As an alternate to reporting excess emissions every 3
contiguous one hour periods as required under paragraphs (a) and (b) of
this section, an owner or operator can petition the Administrator (in
writing) to comply with Sec.  60.43Da(i)(3) of subpart Da of this part.
If the Administrator grants the petition, the source will from then on
(unless the unit is modified or reconstructed in the future) have to
comply with the requirements in Sec.  60.43Da(i)(3) of subpart Da of
this part.
    (e) Units 1 and 2 (as defined in appendix G of this part) at the
Newton Power Station owned or operated by the Central Illinois Public
Service Company will be in compliance with paragraph (a)(2) of this
section if Unit 1 and Unit 2 individually comply with paragraph (a)(2)
of this section or if the combined emission rate from Units 1 and 2
does not exceed 470 ng/J (1.1 lb/MMBtu) combined heat input to Units 1
and 2.

Sec.  60.44  Standard for nitrogen oxides (NOX).

    (a) On and after the date on which the performance test required to
be conducted by 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 any gases that contain
NOX, expressed as NO2 in excess of:
    (1) 86 ng/J heat input (0.20 lb/MMBtu) derived from gaseous fossil
fuel.
    (2) 129 ng/J heat input (0.30 lb/MMBtu) derived from liquid fossil
fuel, liquid fossil fuel and wood residue, or gaseous fossil fuel and
wood residue.
    (3) 300 ng/J heat input (0.70 lb/MMBtu) derived from solid fossil
fuel or solid fossil fuel and wood residue (except lignite or a solid
fossil fuel containing 25 percent, by weight, or more of coal refuse).
    (4) 260 ng/J heat input (0.60 lb MMBtu) derived from lignite or
lignite and wood residue (except as provided under paragraph (a)(5) of
this section).
    (5) 340 ng/J heat input (0.80 lb MMBtu) derived from lignite which
is mined in North Dakota, South Dakota, or Montana and which is burned
in a cyclone-fired unit.
    (b) Except as provided under paragraphs (c) and (d) of this
section, when different fossil fuels are burned simultaneously in any
combination, the applicable standard (in ng/J) is determined by
proration using the following formula:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.001

Where:

PSNOX = Prorated standard for NOX when burning
different fuels simultaneously, in ng/J heat input derived from all
fossil fuels fired or from all fossil fuels and wood residue fired;
w = Percentage of total heat input derived from lignite;
x = Percentage of total heat input derived from gaseous fossil fuel;
y = Percentage of total heat input derived from liquid fossil fuel;
and
z = Percentage of total heat input derived from solid fossil fuel
(except lignite).

    (c) When a fossil fuel containing at least 25 percent, by weight,
of coal refuse is burned in combination with gaseous, liquid, or other
solid fossil fuel or wood residue, the standard for NOX does
not apply.
    (d) Cyclone-fired units which burn fuels containing at least 25
percent of lignite that is mined in North Dakota, South Dakota, or
Montana remain

subject to paragraph (a)(5) of this section regardless of the types of
fuel combusted in combination with that lignite.
    (e) As an alternate to reporting excess emissions every 3
contiguous one hour periods as required under paragraphs (a) and (b) of
this section, an owner or operator can petition the Administrator (in
writing) to comply with Sec.  60.44Da(e)(3) of subpart Da of this part.
If the Administrator grants the petition, the source will from then on
(unless the unit is modified or reconstructed in the future) have to
comply with the requirements in Sec.  60.44Da(e)(3) of subpart Da of
this part.

Sec.  60.45  Emission and fuel monitoring.

    (a) Each owner or operator shall install, calibrate, maintain, and
operate continuous emissions monitoring systems (CEMS) for measuring
the opacity of emissions, SO2 emissions, NOX
emissions, and either oxygen (O2) or carbon dioxide
(CO2) except as provided in paragraph (b) of this section.
    (b) Certain of the CEMS requirements under paragraph (a) of this
section do not apply to owners or operators under the following
conditions:
    (1) For a fossil fuel-fired steam generator that burns only gaseous
fossil fuel and that does not use post combustion technology to reduce
emissions of SO2 or PM, CEMS for measuring the opacity of
emissions and SO2 emissions are not required.
    (2) For a fossil fuel-fired steam generator that does not use a
flue gas desulfurization device, a CEMS for measuring SO2
emissions is not required if the owner or operator monitors
SO2 emissions by fuel sampling and analysis.
    (3) Notwithstanding Sec.  60.13(b), installation of a CEMS for
NOX may be delayed until after the initial performance tests
under Sec.  60.8 have been conducted. If the owner or operator
demonstrates during the performance test that emissions of
NOX are less than 70 percent of the applicable standards in
Sec.  60.44, a CEMS for measuring NOX emissions is not
required. If the initial performance test results show that
NOX emissions are greater than 70 percent of the applicable
standard, the owner or operator shall install a CEMS for NOX
within one year after the date of the initial performance tests under
Sec.  60.8 and comply with all other applicable monitoring requirements
under this part.
    (4) If an owner or operator does not install any CEMS for sulfur
oxides and NOX, as provided under paragraphs (b)(1) and
(b)(3) or paragraphs (b)(2) and (b)(3) of this section a CEMS for
measuring either O2 or CO2 is not required.
    (5) An owner or operator may petition the Administrator (in
writing) to install a PM CEMS as an alternative to the CEMS for
monitoring opacity emissions.
    (c) For performance evaluations under Sec.  60.13(c) and
calibration checks under Sec.  60.13(d), the following procedures shall
be used:
    (1) Methods 6, 7, and 3B of appendix A of this part, as applicable,
shall be used for the performance evaluations of SO2 and
NOX continuous monitoring systems. Acceptable alternative
methods for Methods 6, 7, and 3B of appendix A of this part are given
in Sec.  60.46(d).
    (2) Sulfur dioxide or nitric oxide, as applicable, shall be used
for preparing calibration gas mixtures under Performance Specification
2 of appendix B to this part.
    (3) For affected facilities burning fossil fuel(s), the span value
for a continuous monitoring system measuring the opacity of emissions
shall be 80, 90, or 100 percent and for a continuous monitoring system
measuring sulfur oxides or NOX the span value shall be
determined as follows:

                                             [In parts per million]
----------------------------------------------------------------------------------------------------------------
              Fossil fuel                        Span value for SO2                   Span value for NOX
----------------------------------------------------------------------------------------------------------------
Gas...................................  (\1\)..............................  500
Liquid................................  1,000..............................  500
Solid.................................  1,500..............................  1,000
Combinations..........................  1,000y + 1,000z....................  500 (x + y) + 1,000z
----------------------------------------------------------------------------------------------------------------
\1\ Not applicable.

Where:
x = Fraction of total heat input derived from gaseous fossil fuel;
y = Fraction of total heat input derived from liquid fossil fuel;
and
z = Fraction of total heat input derived from solid fossil fuel.

    (4) All span values computed under paragraph (c)(3) of this section
for burning combinations of fossil fuels shall be rounded to the
nearest 500 ppm.
    (5) For a fossil fuel-fired steam generator that simultaneously
burns fossil fuel and nonfossil fuel, the span value of all CEMS shall
be subject to the Administrator's approval.
    (d) [Reserved]
    (e) For any CEMS installed under paragraph (a) of this section, the
following conversion procedures shall be used to convert the continuous
monitoring data into units of the applicable standards (ng/J, lb/
MMBtu):
    (1) When a CEMS for measuring O2 is selected, the
measurement of the pollutant concentration and O2
concentration shall each be on a consistent basis (wet or dry).
Alternative procedures approved by the Administrator shall be used when
measurements are on a wet basis. When measurements are on a dry basis,
the following conversion procedure shall be used:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.002

Where E, C, F, and %O2 are determined under paragraph (f) of
this section.
    (2) When a CEMS for measuring CO2 is selected, the
measurement of the pollutant concentration and CO2
concentration shall each be on a consistent basis (wet or dry) and the
following conversion procedure shall be used:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.003

Where E, C, Fc and %CO2 are determined under
paragraph (f) of this section.
    (f) The values used in the equations under paragraphs (e) (1) and
(2) of this section are derived as follows:
    (1) E = pollutant emissions, ng/J (lb/MMBtu).
    (2) C = pollutant concentration, ng/dscm (lb/dscf), determined by
multiplying the average concentration (ppm) for each one-hour period by
4.15 x 104 M ng/dscm per ppm (2.59 x 10-9 M lb/
dscf per ppm) where M = pollutant

molecular weight, g/g-mole (lb/lb-mole). M = 64.07 for SO2
and 46.01 for NOX.
    (3) %O2, %CO2 = O2 or
CO2 volume (expressed as percent), determined with equipment
specified under paragraph (a) of this section.
    (4) F, Fc = a factor representing a ratio of the volume
of dry flue gases generated to the calorific value of the fuel
combusted (F), and a factor representing a ratio of the volume of
CO2 generated to the calorific value of the fuel combusted
(Fc), respectively. Values of F and Fc are given
as follows:
    (i) For anthracite coal as classified according to ASTM D388
(incorporated by reference, see Sec.  60.17), F = 2,723 x
10-17 dscm/J (10,140 dscf/MMBtu and Fc = 0.532 x
10-17 scm CO2/J (1,980 scf CO2/MMBtu).
    (ii) For subbituminous and bituminous coal as classified according
to ASTM D388 (incorporated by reference, see Sec.  60.17), F = 2.637 x
10-7 dscm/J (9,820 dscf/MMBtu) and Fc = 0.486 x
10-7 scm CO2/J (1,810 scf CO2/MMBtu).
    (iii) For liquid fossil fuels including crude, residual, and
distillate oils, F = 2.476 x 10-7 dscm/J (9,220 dscf/MMBtu)
and Fc = 0.384 x 10-7 scm CO2/J (1,430
scf CO2/MMBtu).
    (iv) For gaseous fossil fuels, F = 2.347 x 10-7 dscm/J
(8,740 dscf/MMBtu). For natural gas, propane, and butane fuels,
Fc = 0.279 x 10-7 scm CO2/J (1,040 scf
CO2/MMBtu) for natural gas, 0.322 x 10-7 scm
CO2/J (1,200 scf CO2/MMBtu) for propane, and
0.338 x M 10-7 scm CO2/J (1,260 scf
CO2/MMBtu) for butane.
    (v) For bark F = 2.589 x 10-7 dscm/J (9,640 dscf/MMBtu)
and Fc = 0.500 x 10-7 scm CO2/J (1,840
scf CO2/MMBtu). For wood residue other than bark F = 2.492 x
10-7 dscm/J (9,280 dscf/MMBtu) and Fc = 0.494 x
10-7 scm CO2/J (1,860 scf CO2/MMBtu).
    (vi) For lignite coal as classified according to ASTM D388
(incorporated by reference, see Sec.  60.17), F = 2.659 x
10-7 dscm/J (9,900 dscf/MMBtu) and Fc = 0.516x
10-7 scm CO2/J (1,920 scf CO2/MMBtu).
    (5) The owner or operator may use the following equation to
determine an F factor (dscm/J or dscf/MMBtu) on a dry basis (if it is
desired to calculate F on a wet basis, consult the Administrator) or
Fc factor (scm CO2/J, or scf CO2/
MMBtu) on either basis in lieu of the F or Fc factors
specified in paragraph (f)(4) of this section:

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    (i) %H, %C, %S, %N, and %O are content by weight of hydrogen,
carbon, sulfur, nitrogen, and O2 (expressed as percent),
respectively, as determined on the same basis as GCV by ultimate
analysis of the fuel fired, using ASTM D3178 or D3176 (solid fuels), or
computed from results using ASTM D1137, D1945, or D1946 (gaseous fuels)
as applicable. (These five methods are incorporated by reference, see
Sec.  60.17.)
    (ii) GVC is the gross calorific value (kJ/kg, Btu/lb) of the fuel
combusted determined by the ASTM test methods D2015 or D5865 for solid
fuels and D1826 for gaseous fuels as applicable. (These two methods are
incorporated by reference, see Sec.  60.17.)
    (iii) For affected facilities which fire both fossil fuels and
nonfossil fuels, the F or Fc value shall be subject to the
Administrator's approval.
    (6) For affected facilities firing combinations of fossil fuels or
fossil fuels and wood residue, the F or Fc factors determined by
paragraphs (f)(4) or (f)(5) of this section shall be prorated in
accordance with the applicable formula as follows:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.009

Where:

Xi = Fraction of total heat input derived from each type
of fuel (e.g. natural gas, bituminous coal, wood residue, etc.);
Fi or(Fc)i = Applicable F or
Fc factor for each fuel type determined in accordance
with paragraphs (f)(4) and (f)(5) of this section; and
n = Number of fuels being burned in combination.

    (g) Excess emission and monitoring system performance reports shall
be submitted to the Administrator semiannually for each six-month
period in the calendar year. All semiannual reports shall be postmarked
by the 30th day following the end of each six-month period. Each excess
emission and MSP report shall include the information required in Sec.
60.7(c). Periods of excess emissions and monitoring systems (MS)
downtime that shall be reported are defined as follows:
    (1) Opacity. Excess emissions are defined as any six-minute period
during which the average opacity of emissions exceeds 20 percent
opacity, except that one six-minute average per hour of up to 27
percent opacity need not be reported.
    (i) For sources subject to the opacity standard of Sec.
60.42(b)(1), excess emissions are defined as any six-minute period
during which the average opacity of emissions exceeds 35 percent
opacity, except that one six-minute average per hour of up to 42
percent opacity need not be reported.
    (ii) For sources subject to the opacity standard of Sec.
60.42(b)(2), excess emissions are defined as any six-minute period
during which the average opacity of emissions exceeds 32 percent
opacity, except that one six-minute average per hour of up to 39
percent opacity need not be reported.

    (2) Sulfur dioxide. Excess emissions for affected facilities are
defined as:
    (i) Any three-hour period during which the average emissions
(arithmetic average of three contiguous one-hour periods) of
SO2 as measured by a CEMS exceed the applicable standard
under Sec.  60.43, or
    (ii) Any 30 operating day period during which the average emissions
(arithmetic average of all one-hour periods during the 30 operating
days) of SO2 as measured by a CEMS exceed the applicable
standard under Sec.  60.43. Facilities complying with the 30-day
SO2 standard shall use the most current associated
SO2 compliance and monitoring requirements in Sec. Sec.
60.48Da and 60.49Da of subpart Da of this part.
    (3) Nitrogen oxides. Excess emissions for affected facilities using
a CEMS for measuring NOX are defined as:
    (i) Any three-hour period during which the average emissions
(arithmetic average of three contiguous one-hour periods) exceed the
applicable standards under Sec.  60.44, or
    (ii) Any 30 operating day period during which the average emissions
(arithmetic average of all one-hour periods during the 30 operating
days) of NOX as measured by a CEMS exceed the applicable
standard under Sec.  60.43. Facilities complying with the 30-day
NOX standard shall use the most current associated
NOX compliance and monitoring requirements in Sec. Sec.
60.48Da and 60.49Da of subpart Da of this part.
    (4) Particulate matter. Excess emissions for affected facilities
using a CEMS for measuring PM are defined as any boiler operating day
period during which the average emissions (arithmetic average of all
operating one-hour periods) exceed the applicable standards under Sec.
60.43. Affected facilities using PM CEMS in lieu of a CEMS for
monitoring opacity emissions must follow the most current applicable
compliance and monitoring provisions in Sec. Sec.  60.48Da and 60.49Da
of subpart Da of this part.

Sec.  60.46  Test methods and procedures.

    (a) In conducting the performance tests required in Sec.  60.8, and
subsequent performance tests as requested by the EPA Administrator, the
owner or operator shall use as reference methods and procedures the
test methods in appendix A of this part or other methods and procedures
as specified in this section, except as provided in Sec.  60.8(b).
Acceptable alternative methods and procedures are given in paragraph
(d) of this section.
    (b) The owner or operator shall determine compliance with the PM,
SO2, and NOX standards in Sec. Sec.  60.42,
60.43, and 60.44 as follows:
    (1) The emission rate (E) of PM, SO2, or NOX
shall be computed for each run using the following equation:
[GRAPHIC] [TIFF OMITTED] TP09FE07.010

E = Emission rate of pollutant, ng/J (lb/million Btu);
C = Concentration of pollutant, ng/dscm (lb/dscf);
%O2 = O2 concentration, percent dry basis; and
Fd = Factor as determined from Method 19 of appendix A of
this part.

    (2) Method 5 of appendix A of this part shall be used to determine
the PM concentration (C) at affected facilities without wet flue-gas-
desulfurization (FGD) systems and Method 5B of appendix A of this part
shall be used to determine the PM concentration (C) after FGD systems.
    (i) The sampling time and sample volume for each run shall be at
least 60 minutes and 0.85 dscm (30 dscf). The probe and filter holder
heating systems in the sampling train shall be set to provide an
average gas temperature of 160  14 [deg]C (320
25 [deg]F).
    (ii) The emission rate correction factor, integrated or grab
sampling and analysis procedure of Method 3B of appendix A of this part
shall be used to determine the O2 concentration
(%O2). The O2 sample shall be obtained
simultaneously with, and at the same traverse points as, the
particulate sample. If the grab sampling procedure is used, the
O2 concentration for the run shall be the arithmetic mean of
the sample O2 concentrations at all traverse points.
    (iii) If the particulate run has more than 12 traverse points, the
O2 traverse points may be reduced to 12 provided that Method
1 of appendix A of this part is used to locate the 12 O2
traverse points.
    (3) Method 9 of appendix A of this part and the procedures in Sec.
60.11 shall be used to determine opacity.
    (4) Method 6 of appendix A of this part shall be used to determine
the SO2 concentration.
    (i) The sampling site shall be the same as that selected for the
particulate sample. The sampling location in the duct shall be at the
centroid of the cross section or at a point no closer to the walls than
1 m (3.28 ft). The sampling time and sample volume for each sample run
shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Two samples
shall be taken during a 1-hour period, with each sample taken within a
30-minute interval.
    (ii) The emission rate correction factor, integrated sampling and
analysis procedure of Method 3B of appendix A of this part shall be
used to determine the O2 concentration (%O2). The
O2 sample shall be taken simultaneously with, and at the
same point as, the SO2 sample. The SO2 emission
rate shall be computed for each pair of SO2 and
O2 samples. The SO2 emission rate (E) for each
run shall be the arithmetic mean of the results of the two pairs of
samples.
    (5) Method 7 of appendix A of this part shall be used to determine
the NOX concentration.
    (i) The sampling site and location shall be the same as for the
SO2 sample. Each run shall consist of four grab samples,
with each sample taken at about 15-minute intervals.
    (ii) For each NOX sample, the emission rate correction
factor, grab sampling and analysis procedure of Method 3B of appendix A
of this part shall be used to determine the O2 concentration
(%O2). The sample shall be taken simultaneously with, and at
the same point as, the NOX sample.
    (iii) The NOX emission rate shall be computed for each
pair of NOX and O2 samples. The NOX
emission rate (E) for each run shall be the arithmetic mean of the
results of the four pairs of samples.
    (c) When combinations of fossil fuels or fossil fuel and wood
residue are fired, the owner or operator (in order to compute the
prorated standard as shown in Sec. Sec.  60.43(b) and 60.44(b)) shall
determine the percentage (w, x, y, or z) of the total heat input
derived from each type of fuel as follows:
    (1) The heat input rate of each fuel shall be determined by
multiplying the gross calorific value of each fuel fired by the rate of
each fuel burned.
    (2) ASTM Methods D2015, or D5865 (solid fuels), D240 (liquid
fuels), or D1826 (gaseous fuels) (all of these methods are incorporated
by reference, see Sec.  60.17) shall be used to determine the gross
calorific values of the fuels. The method used to determine the
calorific value of wood residue must be approved by the Administrator.
    (3) Suitable methods shall be used to determine the rate of each
fuel burned during each test period, and a material balance over the
steam generating system shall be used to confirm the rate.
    (d) The owner or operator may use the following as alternatives to
the reference methods and procedures in this section or in other
sections as specified:
    (1) The emission rate (E) of PM, SO2 and NOX
may be determined by using the Fc factor, provided that the
following procedure is used:
    (i) The emission rate (E) shall be computed using the following
equation:

[GRAPHIC] [TIFF OMITTED] TP09FE07.011

Where:

E = Emission rate of pollutant, ng/J (lb/MMBtu);
C = Concentration of pollutant, ng/dscm (lb/dscf);
%CO2 = CO2 concentration, percent dry basis;
and
Fc = Factor as determined in appropriate sections of
Method 19 of appendix A of this part.

    (ii) If and only if the average Fc factor in Method 19
of appendix A of this part is used to calculate E and either E is from
0.97 to 1.00 of the emission standard or the relative accuracy of a
continuous emission monitoring system is from 17 to 20 percent, then
three runs of Method 3B of appendix A of this part shall be used to
determine the O2 and CO2 concentration according
to the procedures in paragraph (b) (2)(ii), (4)(ii), or (5)(ii) of this
section. Then if Fo (average of three runs), as calculated
from the equation in Method 3B of appendix A of this part, is more than
3 percent than the average Fo value, as
determined from the average values of Fd and Fc
in Method 19 of appendix A of this part, i.e., Foa = 0.209
(Fda / Fca), then the following procedure shall
be followed:
    (A) When Fo is less than 0.97 Foa, then E
shall be increased by that proportion under 0.97 Foa, e.g.,
if Fo is 0.95 Foa, E shall be increased by 2
percent. This recalculated value shall be used to determine compliance
with the emission standard.
    (B) When Fo is less than 0.97 Foa and when
the average difference (d) between the continuous monitor minus the
reference methods is negative, then E shall be increased by that
proportion under 0.97 Foa, e.g., if Fo is 0.95
Foa, E shall be increased by 2 percent. This recalculated
value shall be used to determine compliance with the relative accuracy
specification.
    (C) When Fo is greater than 1.03 Foa and when
the average difference d is positive, then E shall be decreased by that
proportion over 1.03 Foa, e.g., if Fo is 1.05
Foa, E shall be decreased by 2 percent. This recalculated
value shall be used to determine compliance with the relative accuracy
specification.
    (2) For Method 5 or 5B of appendix A of this part, Method 17 of
appendix A of this part may be used at facilities with or without wet
FGD systems if the stack gas temperature at the sampling location does
not exceed an average temperature of 160 [deg]C (320 [deg]F). The
procedures of sections 2.1 and 2.3 of Method 5B of appendix A of this
part may be used with Method 17 of appendix A of this part only if it
is used after wet FGD systems. Method 17 of appendix A of this part
shall not be used after wet FGD systems if the effluent gas is
saturated or laden with water droplets.
    (3) Particulate matter and SO2 may be determined
simultaneously with the Method 5 of appendix A of this part train
provided that the following changes are made:
    (i) The filter and impinger apparatus in sections 2.1.5 and 2.1.6
of Method 8 of appendix A of this part is used in place of the
condenser (section 2.1.7) of Method 5 of appendix A of this part.
    (ii) All applicable procedures in Method 8 of appendix A of this
part for the determination of SO2 (including moisture) are
used:
    (4) For Method 6 of appendix A of this part, Method 6C of appendix
A of this part may be used. Method 6A of appendix A of this part may
also be used whenever Methods 6 and 3B of appendix A of this part data
are specified to determine the SO2 emission rate, under the
conditions in paragraph (d)(1) of this section.
    (5) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or
7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of
appendix A of this part is used, the sampling time for each run shall
be at least 1 hour and the integrated sampling approach shall be used
to determine the O2 concentration (%O2) for the
emission rate correction factor.
    (6) For Method 3 of appendix A of this part, Method 3A or 3B of
appendix A of this part may be used.
    (7) For Method 3B of appendix A of this part, Method 3A of appendix
A of this part may be used.

Subpart Da--[Amended]

    4. Subpart Da is revised as follows:
Subpart Da--Standards of Performance for Electric Utility Steam
Generating Units for Which Construction Is Commenced After September
18, 1978
Sec.
60.40Da Applicability and designation of affected facility.
60.41Da Definitions.
60.42Da Standard for particulate matter (PM).
60.43Da Standard for sulfur dioxide (SO2).
60.44Da Standard for nitrogen oxides (NOX).
60.45Da Standard for mercury (Hg).
60.46Da [Reserved]
60.47Da Commercial demonstration permit.
60.48Da Compliance provisions.
60.49Da Emission monitoring.
60.50Da Compliance determination procedures and methods.
60.51Da Reporting requirements.
60.52Da Recordkeeping requirements.

Subpart Da--Standards of Performance for Electric Utility Steam
Generating Units for Which Construction Is Commenced After
September 18, 1978

Sec.  60.40Da  Applicability and designation of affected facility.

    (a) The affected facility to which this subpart applies is each
electric utility steam-generating unit:
    (1) That is capable of combusting more than 73 megawatts (MW) (250
million British thermal units per hour (MMBtu/hr)) heat input of fossil
fuel (either alone or in combination with any other fuel); and
    (2) For which construction, modification, or reconstruction is
commenced after September 18, 1978.
    (b) Combined cycle gas turbines (both the stationary combustion
turbine and any associated duct burners) are subject to this part and
not subject to subpart GG or KKKK of this part if:
    (1) The combined cycle gas turbine is capable of combusting more
than 73 MW (250 MMBtu/hr) heat input of fossil fuel (either alone or in
combination with any other fuel); and
    (2) The combined cycle gas turbine is designed and intended to burn
fuels containing 50 percent (by heat input) or more solid-derived fuel
not meeting the definition of natural gas on a 12-month rolling average
basis; and
    (3) The combined cycle gas turbine commenced construction,
modification, or reconstruction after February 28, 2005.
    (4) 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/hr) heat input of fossil fuel in the heat
recovery steam generator. If the heat recovery steam generator is
subject to this subpart and the stationary combustion turbine is
subject to either subpart GG or KKKK of this part, only emissions
resulting from combustion of fuels in the steam-generating unit are
subject to this subpart. (The stationary combustion turbine emissions
are subject to subpart GG or KKKK, as applicable, of this part).
    (c) Any change to an existing fossil-fuel-fired steam generating
unit to accommodate the use of combustible materials, other than fossil
fuels, shall not bring that unit under the applicability of this
subpart.
    (d) Any change to an existing steam generating unit originally
designed to fire gaseous or liquid fossil fuels, to accommodate the use
of any other fuel

(fossil or nonfossil) shall not bring that unit under the applicability
of this subpart.

Sec.  60.41Da  Definitions.

    As used in this subpart, all terms not defined herein shall have
the meaning given them in the Act and in subpart A of this part.
    Anthracite means coal that is classified as anthracite according to
the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec.  60.17).
    Available purchase power means the lesser of the following:
    (a) The sum of available system capacity in all neighboring
companies.
    (b) The sum of the rated capacities of the power interconnection
devices between the principal company and all neighboring companies,
minus the sum of the electric power load on these interconnections.
    (c) The rated capacity of the power transmission lines between the
power interconnection devices and the electric generating units (the
unit in the principal company that has the malfunctioning flue gas
desulfurization system and the unit(s) in the neighboring company
supplying replacement electrical power) less the electric power load on
these transmission lines.
    Available system capacity means the capacity determined by
subtracting the system load and the system emergency reserves from the
net system capacity.
    Biomass means plant materials and animal waste.
    Bituminous coal means coal that is classified as bituminous
according to the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec.  60.17).
    Boiler operating day for units constructed, reconstructed, or
modified on or before February 28, 2005, means a 24-hour period during
which fossil fuel is combusted in a steam-generating unit for the
entire 24 hours. For units constructed, reconstructed, or modified
after February 28, 2005, boiler operating day means a 24-hour period
between 12 midnight and the following midnight during which any fuel is
combusted at any time in the steam-generating unit. It is not necessary
for fuel to be combusted the entire 24-hour period.
    Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec.  60.17) and
coal refuse. Synthetic fuels derived from coal for the purpose of
creating useful heat, including but not limited to solvent-refined
coal, gasified coal, coal-oil mixtures, and coal-water mixtures are
included in this definition for the purposes of this subpart.
    Coal-fired electric utility steam generating unit means an electric
utility steam generating unit that burns coal, coal refuse, or a
synthetic gas derived from coal either exclusively, in any combination
together, or in any combination with other fuels in any amount.
    Coal refuse means waste products of coal mining, physical coal
cleaning, and coal preparation operations (e.g. culm, gob, etc.)
containing coal, matrix material, clay, and other organic and inorganic
material.
    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.
    Combined cycle gas turbine means a stationary turbine combustion
system where heat from the turbine exhaust gases is recovered by a
steam generating unit.
    Dry flue gas desulfurization technology or dry FGD means a sulfur
dioxide control system that is located downstream of the steam
generating unit and removes sulfur oxides (SO2) from the
combustion gases of the steam generating unit by contacting the
combustion gases with an alkaline slurry or solution and forming a dry
powder material. This definition includes devices where the dry powder
material is subsequently converted to another form. Alkaline slurries
or solutions used in dry FGD technology include, but are not limited
to, lime and sodium.
    Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source, such as a stationary gas turbine,
internal combustion engine, kiln, etc., to allow the firing of
additional fuel to heat the exhaust gases before the exhaust gases
enter a heat recovery steam generating unit.
    Electric utility combined cycle gas turbine means any combined
cycle gas turbine used for electric generation that is constructed for
the purpose of supplying more than one-third of its potential electric
output capacity and more than 219,000 megawatt hour (MWh) net
electrical output to any utility power distribution system for sale.
Any steam distribution system that is constructed for the purpose of
providing steam to a steam electric generator that would produce
electrical power for sale is also considered in determining the
electrical energy output capacity of the affected facility.
    Electric utility company means the largest interconnected
organization, business, or governmental entity that generates electric
power for sale (e.g., a holding company with operating subsidiary
companies).
    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
219,000 MWh net-electrical output to any utility power distribution
system for sale. 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.
    Electrostatic precipitator or ESP means an add-on air pollution
control device used to capture particulate matter (PM) by charging the
particles using an electrostatic field, collecting the particles using
a grounded collecting surface, and transporting the particles into a
hopper.
    Emergency condition means that period of time when:
    (1) The electric generation output of an affected facility with a
malfunctioning flue gas desulfurization system cannot be reduced or
electrical output must be increased because:
    (i) All available system capacity in the principal company
interconnected with the affected facility is being operated, and
    (ii) All available purchase power interconnected with the affected
facility is being obtained, or
    (2) The electric generation demand is being shifted as quickly as
possible from an affected facility with a malfunctioning flue gas
desulfurization system to one or more electrical generating units held
in reserve by the principal company or by a neighboring company, or
    (3) An affected facility with a malfunctioning flue gas
desulfurization system becomes the only available unit to maintain a
part or all of the principal company's system emergency reserves and
the unit is operated in spinning reserve at the lowest practical
electric generation load consistent with not causing significant
physical damage to the unit. If the unit is operated at a higher load
to meet load demand, an emergency condition would not exist unless the
conditions under paragraph (1) of this definition apply.
    Emission limitation means any emissions limit or operating limit.

    Emission rate period means any calendar month included in a 12-
month rolling average period.
    Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State
implementation plan, and any permit requirements established under 40
CFR 52.21 or under 40 CFR 51.18 and 51.24.
    Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such material for the
purpose of creating useful heat.
    Gaseous fuel means any fuel derived from coal or petroleum that is
present as a gas at standard conditions and includes, but is not
limited to, refinery fuel gas, process gas, coke-oven gas, synthetic
gas, and gasified coal.
    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 or mechanical 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).
    24-hour period means the period of time between 12:01 a.m. and 12
midnight.
    Integrated gasification combined cycle electric utility steam
generating unit or IGCC means a coal-fired electric utility steam
generating unit that burns a synthetic gas derived from coal in a
combined-cycle gas turbine. No coal is directly burned in the unit
during operation.
    Interconnected means that two or more electric generating units are
electrically tied together by a network of power transmission lines,
and other power transmission equipment.
    ISO conditions means a temperature of 288 Kelvin, a relative
humidity of 60 percent, and a pressure of 101.3 kilopascals.
    Lignite means coal that is classified as lignite A or B according
to the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec.  60.17).
    Natural gas means:
    (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon
gases found in geologic formations beneath the earth's surface, of
which the principal constituent is methane; or
    (2) Liquid petroleum gas, as defined by the American Society of
Testing and Materials in ASTM D1835 (incorporated by reference, see
Sec.  60.17); or
    (3) A mixture of hydrocarbons that maintains a gaseous state at ISO
conditions. Additionally, natural gas must either be composed of at
least 70 percent methane by volume or have a gross calorific value
between 34 and 43 megajoules (MJ) per standard cubic meter (910 and
1,150 Btu per standard cubic foot).
    Neighboring company means any one of those electric utility
companies with one or more electric power interconnections to the
principal company and which have geographically adjoining service
areas.
    Net-electric output means the gross electric sales to the utility
power distribution system minus purchased power on a calendar year
basis.
    Net system capacity means the sum of the net electric generating
capability (not necessarily equal to rated capacity) of all electric
generating equipment owned by an electric utility company (including
steam generating units, internal combustion engines, gas turbines,
nuclear units, hydroelectric units, and all other electric generating
equipment) plus firm contractual purchases that are interconnected to
the affected facility that has the malfunctioning flue gas
desulfurization system. The electric generating capability of equipment
under multiple ownership is prorated based on ownership unless the
proportional entitlement to electric output is otherwise established by
contractual arrangement.
    Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
    Petroleum means crude oil or petroleum or a fuel derived from crude
oil or petroleum, including, but not limited to, distillate oil,
residual oil, and petroleum coke.
    Potential combustion concentration means the theoretical emissions
(nanograms per joule (ng/J), lb/MMBtu heat input) that would result
from combustion of a fuel in an uncleaned state without emission
control systems) and:
    (1) For particulate matter (PM) is:
    (i) 3,000 ng/J (7.0 lb/MMBtu) heat input for solid fuel; and
    (ii) 73 ng/J (0.17 lb/MMBtu) heat input for liquid fuels.
    (2) For sulfur dioxide (SO2) is determined under Sec.
60.50Da(c).
    (3) For nitrogen oxides (NOX) is:
    (i) 290 ng/J (0.67 lb/MMBtu) heat input for gaseous fuels;
    (ii) 310 ng/J (0.72 lb/MMBtu) heat input for liquid fuels; and
    (iii) 990 ng/J (2.30 lb/MMBtu) heat input for solid fuels.
    Potential electrical output capacity means 33 percent of the
maximum design heat input capacity of the steam generating unit,
divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by
8,760 hr/yr (e.g., a steam generating unit with a 100 MW (340 MMBtu/hr)
fossil-fuel heat input capacity would have a 289,080 MWh 12 month
potential electrical output capacity). For electric utility combined
cycle gas turbines the potential electrical output capacity is
determined on the basis of the fossil-fuel firing capacity of the steam
generator exclusive of the heat input and electrical power contribution
by the gas turbine.
    Principal company means the electric utility company or companies
which own the affected facility.
    Resource recovery unit means a facility that combusts more than 75
percent non-fossil fuel on a quarterly (calendar) heat input basis.
    Responsible official means responsible official as defined in 40
CFR 70.2.
    Solid-derived fuel means any solid, liquid, or gaseous fuel derived
from solid fuel for the purpose of creating useful heat and includes,
but is not limited to, solvent refined coal, liquified coal, synthetic
gas, gasified coal, gasified petroleum coke, gasified biomass, and
gasified tire derived fuel.
    Spare flue gas desulfurization system module means a separate