

[Federal Register: February 9, 2007 (Volume 72, Number 27)]
[Proposed Rules]               
[Page 6319-6375]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr09fe07-16]                         


[[Page 6319]]

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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


[[Page 6320]]


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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: a-and-r-docket@epa.gov.
     By Facsimile: (202) 566-1741.
     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 (202) 566-1744, and the telephone 
number for the Air and Radiation Docket is (202) 566-1742.

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 (919) 541-4003, 
facsimile number (919) 541-5450, electronic mail (e-mail) address: 
fellner.christian@epa.gov.


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
------------------------------------------------------------------------
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.

[[Page 6321]]


                                            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.
------------------------------------------------------------------------
\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 919-541-4003 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

[[Page 6322]]

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

[[Page 6323]]

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

[[Page 6324]]

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

[[Page 6325]]

(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.

[[Page 6326]]

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

[[Page 6327]]

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.

[[Page 6328]]

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, 12.5.2.2.3.
    (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 12.5.2.2.3.
    (12) ASTM D270-65, 75, Standard Method of Sampling Petroleum and 
Petroleum Products, IBR approved for Appendix A: Method 19, Section 
12.5.2.2.1.
    (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 12.5.2.2.3.
    (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 
12.3.2.4.
    (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 
12.5.2.1.3.
    (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

[[Page 6329]]

approved for Appendix A: Method 19, Section 12.5.2.1.3.
    (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 
12.5.2.1.1.
    (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 7.1.1.2.
    (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 12.5.2.1.3.
    (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 
12.3.2.3.
    (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 12.5.2.1.3.
    (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 12.5.2.1.3.
    (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 12.5.2.2.3.
    (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 12.5.2.2.1.
    (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 
12.5.2.1.3.
    (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

[[Page 6330]]

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 12.5.2.1.3.
    (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.

[[Page 6331]]

    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

[[Page 6332]]

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

[[Page 6333]]

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.

[[Page 6334]]

    (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:

[[Page 6335]]

[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

[[Page 6336]]

(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.

[[Page 6337]]

    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 
system of SO2 emission control equipment capable of treating 
an amount of flue gas equal to the total amount of flue gas generated 
by an affected facility when operated at maximum capacity divided by 
the total number of nonspare flue gas desulfurization modules in the 
system.
    Spinning reserve means the sum of the unutilized net generating 
capability of all units of the electric utility company that are 
synchronized to the power distribution system and that are capable of 
immediately accepting additional load. 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.
    Steam generating unit means any furnace, boiler, or other device 
used for combusting fuel for the purpose of producing steam (including 
fossil-fuel-fired steam generators associated with

[[Page 6338]]

combined cycle gas turbines; nuclear steam generators are not 
included).
    Subbituminous coal means coal that is classified as subbituminous 
A, B, or C according to the American Society of Testing and Materials 
in ASTM D388 (incorporated by reference, see Sec.  60.17).
    System emergency reserves means an amount of electric generating 
capacity equivalent to the rated capacity of the single largest 
electric generating unit in the electric utility company (including 
steam generating units, internal combustion engines, gas turbines, 
nuclear units, hydroelectric units, and all other electric generating 
equipment) which is interconnected with 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.
    System load means the entire electric demand of an electric utility 
company's service area interconnected with the affected facility that 
has the malfunctioning flue gas desulfurization system plus firm 
contractual sales to other electric utility companies. Sales to other 
electric utility companies (e.g., emergency power) not on a firm 
contractual basis may also be included in the system load when no 
available system capacity exists in the electric utility company to 
which the power is supplied for sale.
    Wet flue gas desulfurization technology or wet FGD means a 
SO2 control system that is located downstream of the steam 
generating unit and removes sulfur oxides from the combustion gases of 
the steam generating unit by contacting the combustion gases with an 
alkaline slurry or solution and forming a liquid material. This 
definition applies to devices where the aqueous liquid material product 
of this contact is subsequently converted to other forms. Alkaline 
reagents used in wet FGD technology include, but are not limited to, 
lime, limestone, and sodium.


Sec.  60.42Da  Standard for particulate matter (PM).

    (a) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator subject to the provisions of this 
subpart shall cause to be discharged into the atmosphere from any 
affected facility for which construction, reconstruction, or 
modification commenced before or on February 28, 2005, any gases that 
contain PM in excess of:
    (1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion 
of solid, liquid, or gaseous fuel;
    (2) 1 percent of the potential combustion concentration (99 percent 
reduction) when combusting solid fuel; and
    (3) 30 percent of potential combustion concentration (70 percent 
reduction) when combusting liquid fuel.
    (b) On and after the date the initial PM performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, 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 which exhibit greater than 20 percent 
opacity (6-minute average), except for one 6-minute period per hour of 
not more than 27 percent opacity.
    (c) Except as provided in paragraph (d) of this section, on and 
after the date on which the initial performance test is completed or 
required to be completed under Sec.  60.8, whichever date comes first, 
no owner or operator of an affected facility that commenced 
construction, reconstruction, or modification after February 28, 2005 
shall cause to be discharged into the atmosphere from that affected 
facility any gases that contain PM in excess of either:
    (1) 18 ng/J (0.14 lb/MWh) gross energy output; or
    (2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the 
combustion of solid, liquid, or gaseous fuel.
    (d) As an alternative to meeting the requirements of paragraph (c) 
of this section, the owner or operator of an affected facility for 
which construction, reconstruction, or modification commenced after 
February 28, 2005, may elect to meet the requirements of this 
paragraph. On and after the date on which the initial performance test 
is completed or required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility shall 
cause to be discharged into the atmosphere from that affected facility 
for which construction, reconstruction, or modification commenced after 
February 28, 2005, any gases that contain PM in excess of:
    (1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion 
of solid, liquid, or gaseous fuel, and
    (2) 0.1 percent of the combustion concentration determined 
according to the procedure in Sec.  60.48Da(o)(5) (99.9 percent 
reduction) for an affected facility for which construction or 
reconstruction commenced after February 28, 2005 when combusting solid, 
liquid, or gaseous fuel, or
    (3) 0.2 percent of the combustion concentration determined 
according to the procedure in Sec.  60.48Da(o)(5) (99.8 percent 
reduction) for an affected facility for which modification commenced 
after February 28, 2005 when combusting solid, liquid, or gaseous fuel.


Sec.  60.43Da  Standard for sulfur dioxide (SO2).

    (a) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator subject to the provisions of this 
subpart shall cause to be discharged into the atmosphere from any 
affected facility which combusts solid fuel or solid-derived fuel and 
for which construction, reconstruction, or modification commenced 
before or on February 28, 2005, except as provided under paragraphs 
(c), (d), (f) or (h) of this section, any gases that contain 
SO2 in excess of:
    (1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the 
potential combustion concentration (90 percent reduction); or
    (2) 30 percent of the potential combustion concentration (70 
percent reduction), when emissions are less than 260 ng/J (0.60 lb/
MMBtu) heat input.
    (b) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator subject to the provisions of this 
subpart shall cause to be discharged into the atmosphere from any 
affected facility which combusts liquid or gaseous fuels (except for 
liquid or gaseous fuels derived from solid fuels and as provided under 
paragraphs (e) or (h) of this section) and for which construction, 
reconstruction, or modification commenced before or on February 28, 
2005, any gases that contain SO2 in excess of:
    (1) 340 ng/J (0.80 lb/MMBtu) heat input and 10 percent of the 
potential combustion concentration (90 percent reduction); or
    (2) 100 percent of the potential combustion concentration (zero 
percent reduction) when emissions are less than 86 ng/J (0.20 lb/MMBtu) 
heat input.
    (c) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator subject to the provisions of this 
subpart shall cause to be discharged into the atmosphere from any 
affected facility which combusts solid solvent

[[Page 6339]]

refined coal (SRC-I) any gases that contain SO2 in excess of 
520 ng/J (1.20 lb/MMBtu) heat input and 15 percent of the potential 
combustion concentration (85 percent reduction) except as provided 
under paragraph (f) of this section; compliance with the emission 
limitation is determined on a 30-day rolling average basis and 
compliance with the percent reduction requirement is determined on a 
24-hour basis.
    (d) Sulfur dioxide emissions are limited to 520 ng/J (1.20 lb/
MMBtu) heat input from any affected facility which:
    (1) Combusts 100 percent anthracite;
    (2) Is classified as a resource recovery unit; or
    (3) Is located in a noncontinental area and combusts solid fuel or 
solid-derived fuel.
    (e) Sulfur dioxide emissions are limited to 340 ng/J (0.80 lb/
MMBtu) heat input from any affected facility which is located in a 
noncontinental area and combusts liquid or gaseous fuels (excluding 
solid-derived fuels).
    (f) The emission reduction requirements under this section do not 
apply to any affected facility that is operated under an SO2 
commercial demonstration permit issued by the Administrator in 
accordance with the provisions of Sec.  60.47Da.
    (g) Compliance with the emission limitation and percent reduction 
requirements under this section are both determined on a 30-day rolling 
average basis except as provided under paragraph (c) of this section.
    (h) When different fuels are combusted simultaneously, the 
applicable standard is determined by proration using the following 
formula:
    (1) If emissions of SO2 to the atmosphere are greater 
than 260 ng/J (0.60 lb/MMBtu) heat input.

 [GRAPHIC] [TIFF OMITTED] TP09FE07.012


    (2) If emissions of SO2 to the atmosphere are equal to 
or less than 260 ng/J (0.60 lb/MMBtu) heat input:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.013


Where:

Es = Prorated SO2 emission limit (ng/J heat 
input);
%Ps = Percentage of potential SO2 emission 
allowed;
x = Percentage of total heat input derived from the combustion of 
liquid or gaseous fuels (excluding solid-derived fuels); and
y = Percentage of total heat input derived from the combustion of 
solid fuel (including solid-derived fuels).

    (i) Except as provided in paragraphs (j) and (k) of this section, 
on and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that 
commenced construction, reconstruction, or modification commenced after 
February 28, 2005 shall cause to be discharged into the atmosphere from 
that affected facility, any gases that contain SO2 in excess 
of the applicable emission limitation specified in paragraphs (i)(1) 
through (3) of this section.
    (1) For an affected facility for which construction commenced after 
February 28, 2005, any gases that contain SO2 in excess of 
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis; or
    (ii) 5 percent of the potential combustion concentration (95 
percent reduction) on a 30-day rolling average basis.
    (2) For an affected facility for which reconstruction commenced 
after February 28, 2005, any gases that contain SO2 in 
excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average 
basis; or
    (iii) 5 percent of the potential combustion concentration (95 
percent reduction) on a 30-day rolling average basis.
    (3) For an affected facility for which modification commenced after 
February 28, 2005, any gases that contain SO2 in excess of 
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average 
basis; or
    (iii) 10 percent of the potential combustion concentration (90 
percent reduction) on a 30-day rolling average basis.
    (j) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that 
commenced construction, reconstruction, or modification commenced after 
February 28, 2005, and that burns 75 percent or more (by heat input) 
coal refuse on a 12-month rolling average basis, shall caused to be 
discharged into the atmosphere from that affected facility any gases 
that contain SO2 in excess of the applicable emission 
limitation specified in paragraphs (j)(1) through (3) of this section.
    (1) For an affected facility for which construction commenced after 
February 28, 2005, any gases that contain SO2 in excess of 
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis; or
    (ii) 6 percent of the potential combustion concentration (94 
percent reduction) on a 30-day rolling average basis.
    (2) For an affected facility for which reconstruction commenced 
after February 28, 2005, any gases that contain SO2 in 
excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average 
basis; or
    (iii) 6 percent of the potential combustion concentration (94 
percent reduction) on a 30-day rolling average basis.
    (3) For an affected facility for which modification commenced after 
February 28, 2005, any gases that contain SO2 in excess of 
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average 
basis; or
    (iii) 10 percent of the potential combustion concentration (90 
percent reduction) on a 30-day rolling average basis.
    (k) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility located in a 
noncontinental area that commenced construction, reconstruction, or 
modification commenced after February 28, 2005, shall cause to be 
discharged into the atmosphere from that affected facility any gases 
that contain SO2 in excess of the applicable emission 
limitation specified in paragraphs (k)(1) and (2) of this section.
    (1) For an affected facility that burns solid or solid-derived 
fuel, the owner or operator shall not cause to be discharged into the 
atmosphere any gases that contain SO2 in excess of 520 ng/J 
(1.2 lb/MMBtu) heat input on a 30-day rolling average basis.
    (2) For an affected facility that burns other than solid or solid-
derived fuel, the owner or operator shall not cause to be discharged 
into the atmosphere any

[[Page 6340]]

gases that contain SO2 in excess of if the affected facility 
or 230 ng/J (0.54 lb/MMBtu) heat input on a 30-day rolling average 
basis.


Sec.  60.44Da  Standard for nitrogen oxides (NOX).

    (a) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator subject to the provisions of this 
subpart shall cause to be discharged into the atmosphere from any 
affected facility, except as provided under paragraphs (b), (d), (e), 
and (f) of this section, any gases that contain NOX 
(expressed as NO2) in excess of the following emission 
limits, based on a 30-day rolling average basis, except as provided 
under Sec.  60.48Da(j)(1):
    (1) NOX emission limits.

------------------------------------------------------------------------
                                                 Emission limit for heat
                                                          input
                   Fuel type                   -------------------------
                                                    ng/J       lb/MMBtu
------------------------------------------------------------------------
Gaseous fuels:
    Coal-derived fuels........................          210         0.50
    All other fuels...........................           86         0.20
Liquid fuels:
    Coal-derived fuels........................          210         0.50
    Shale oil.................................          210         0.50
    All other fuels...........................          130         0.30
Solid fuels:
    Coal-derived fuels........................          210         0.50
    Any fuel containing more than 25%, by
     weight, coal refuse\1\...................
    Any fuel containing more than 25%, by               340         0.80
     weight, lignite if the lignite is mined
     in North Dakota, South Dakota, or
     Montana, and is combusted in a slag tap
     furnace \2\..............................
    Any fuel containing more than 25%, by               260         0.60
     weight, lignite not subject to the 340 ng/
     J heat input emission limit \2\..........
    Subbituminous coal........................          210         0.50
    Bituminous coal...........................          260         0.60
    Anthracite coal...........................          260         0.60
    All other fuels...........................          260        0.60
------------------------------------------------------------------------
\1\ Exempt from NOX standards and NOX monitoring requirements.
\2\ Any fuel containing less than 25%, by weight, lignite is not
  prorated but its percentage is added to the percentage of the
  predominant fuel.

    (2) NOX reduction requirement.

------------------------------------------------------------------------
                                                             Percent
                                                          reduction of
                       Fuel type                            potential
                                                           combustion
                                                          concentration
------------------------------------------------------------------------
Gaseous fuels.........................................                25
Liquid fuels..........................................                30
Solid fuels...........................................                65
------------------------------------------------------------------------

    (b) The emission limitations under paragraph (a) of this section do 
not apply to any affected facility which is combusting coal-derived 
liquid fuel and is operating under a commercial demonstration permit 
issued by the Administrator in accordance with the provisions of Sec.  
60.47Da.
    (c) Except as provided under paragraphs (d), (e), and (f) of this 
section, when two or more fuels are combusted simultaneously, the 
applicable standard is determined by proration using the following 
formula:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.014


Where:

En = Applicable standard for NOX when multiple 
fuels are combusted simultaneously (ng/J heat input);
w = Percentage of total heat input derived from the combustion of 
fuels subject to the 86 ng/J heat input standard;
x = Percentage of total heat input derived from the combustion of 
fuels subject to the 130 ng/J heat input standard;
y = Percentage of total heat input derived from the combustion of 
fuels subject to the 210 ng/J heat input standard;
z = Percentage of total heat input derived from the combustion of 
fuels subject to the 260 ng/J heat input standard; and
v = Percentage of total heat input delivered from the combustion of 
fuels subject to the 340 ng/J heat input standard.

    (d)(1) On and after the date on which the initial performance test 
is completed or required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
commenced construction after July 9, 1997, but before or on February 
28, 2005 shall cause to the atmosphere any gases that contain 
NOX (expressed as NO2) in excess of 200 ng/J (1.6 
lb/MWh) gross energy output, based on a 30-day rolling average basis, 
except as provided under Sec.  60.48Da(k).
    (2) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of affected facility for which 
reconstruction commenced after July 9, 1997, but before or on February 
28, 2005 shall cause to be discharged into the atmosphere any gases 
that contain NOX (expressed as NO2) in excess of 
65 ng/J (0.15 lb/MMBtu) heat input, based on a 30-day rolling average 
basis.
    (e) Except for an IGCC meeting the requirements of paragraph (f) of 
this section, on and after the date on which the initial performance 
test is completed or required to be completed under Sec.  60.8, 
whichever date comes first, no owner or operator of an affected 
facility that commenced construction, reconstruction, or modification 
after February 28, 2005 shall cause to be discharged into the 
atmosphere from that affected facility any gases that contain 
NOX (expressed as NO2) in excess of the 
applicable emission limitation specified in paragraphs (e)(1) through 
(3) of this section.
    (1) For an affected facility for which construction commenced after 
February 28, 2005, the owner or operator shall not cause to be 
discharged into the atmosphere any gases that contain NOX 
(expressed as NO2) in excess of 130 ng/J (1.0 lb/MWh) gross 
energy output on a 30-day rolling average basis, except as provided 
under Sec.  60.48Da(k).
    (2) For an affected facility for which reconstruction commenced 
after February 28, 2005, the owner or operator shall not cause to be 
discharged into the atmosphere any gases that contain NOX 
(expressed as NO2) in excess of either:

[[Page 6341]]

    (i) 130 ng/J (1.0 lb/MWh) gross energy output on a 30-day rolling 
average basis; or
    (ii) 47 ng/J (0.11 lb/MMBtu) heat input on a 30-day rolling average 
basis.
    (3) For an affected facility for which modification commenced after 
February 28, 2005, the owner or operator shall not cause to be 
discharged into the atmosphere any gases that contain NOX 
(expressed as NO2) in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling 
average basis; or
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average 
basis.
    (f) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an IGCC subject to the provisions 
of this subpart that burns liquid fuel as a supplemental fuel and for 
which construction, reconstruction, or modification commenced after 
February 28, 2005, shall meet the requirements specified in paragraphs 
(f)(1) through (3) of this section.
    (1) The owner or operator shall not cause to be discharged into the 
atmosphere any gases that contain NOX (expressed as 
NO2) in excess of 130 ng/J (1.0 lb/MWh) gross energy output 
on a 30-day rolling average basis, except as provided for in paragraphs 
(f)(2) and (3) of this section.
    (2) When burning liquid fuel exclusively or in combination with 
solid-derived fuel such that the liquid fuel contributes 50 percent or 
more of the total heat input to the combined cycle combustion turbine, 
the owner or operator shall not cause to be discharged into the 
atmosphere any gases that contain NOX (expressed as 
NO2) in excess of 190 ng/J (1.5 lb/MWh) gross energy output 
on a 30-day rolling average basis.
    (3) In cases when during a 30-day rolling average compliance period 
liquid fuel is burned in such a manner to meet the conditions in 
paragraph (f)(2) of this section for only a portion of the clock hours 
in the 30-day period, the owner or operator shall not cause to be 
discharged into the atmosphere any gases that contain NOX 
(expressed as NO2) in excess of the computed weighted-
average emissions limit based on the proportion of gross energy output 
(in MWh) generated during the compliance period for each of emissions 
limits in paragraphs (f)(1) and (2) of this section.


Sec.  60.45Da  Standard for mercury (Hg).

    (a) For each coal-fired electric utility steam generating unit 
other than an IGCC electric utility steam generating unit, on and after 
the date on which the initial performance test is completed or required 
to be completed under Sec.  60.8, whichever date comes first, no owner 
or operator subject to the provisions of this subpart shall cause to be 
discharged into the atmosphere from any affected facility for which 
construction, modification, or reconstruction commenced after January 
30, 2004, any gases that contain mercury (Hg) emissions in excess of 
each Hg emissions limit in paragraphs (a)(1) through (5) of this 
section that applies to you. The Hg emissions limits in paragraphs 
(a)(1) through (5) of this section are based on a 12-month rolling 
average basis using the procedures in Sec.  60.50Da(h).
    (1) For each coal-fired electric utility steam generating unit that 
burns only bituminous coal, you must not discharge into the atmosphere 
any gases from a new affected source that contain Hg in excess of 20 x 
10-6 pound per megawatt hour (lb/MWh) or 0.020 lb/gigawatt-
hour (GWh) on an output basis. The International System of Units (SI) 
equivalent is 0.0025 ng/J.
    (2) For each coal-fired electric utility steam generating unit that 
burns only subbituminous coal:
    (i) If your unit is located in a county-level geographical area 
receiving greater than 25 inches per year (in/yr) mean annual 
precipitation, based on the most recent publicly available U.S. 
Department of Agriculture 30-year data, you must not discharge into the 
atmosphere any gases from a new affected source that contain Hg in 
excess of 66 x 10-6 lb/MWh or 0.066 lb/GWh on an output 
basis. The SI equivalent is 0.0083 ng/J.
    (ii) If your unit is located in a county-level geographical area 
receiving less than or equal to 25 in/yr mean annual precipitation, 
based on the most recent publicly available U.S. Department of 
Agriculture 30-year data, you must not discharge into the atmosphere 
any gases from a new affected source that contain Hg in excess of 97 x 
10-6 lb/MWh or 0.097 lb/GWh on an output basis. The SI 
equivalent is 0.0122 ng/J.
    (3) For each coal-fired electric utility steam generating unit that 
burns only lignite, you must not discharge into the atmosphere any 
gases from a new affected source that contain Hg in excess of 175 x 
10-6 lb/MWh or 0.175 lb/GWh on an output basis. The SI 
equivalent is 0.0221 ng/J.
    (4) For each coal-burning electric utility steam generating unit 
that burns only coal refuse, you must not discharge into the atmosphere 
any gases from a new affected source that contain Hg in excess of 16 x 
10-6 lb/MWh or 0.016 lb/GWh on an output basis. The SI 
equivalent is 0.0020 ng/J.
    (5) For each coal-fired electric utility steam generating unit that 
burns a blend of coals from different coal ranks (i.e., bituminous 
coal, subbituminous coal, lignite) or a blend of coal and coal refuse, 
you must not discharge into the atmosphere any gases from a new 
affected source that contain Hg in excess of the unit-specific Hg 
emissions limit established according to paragraph (a)(5)(i) or (ii) of 
this section, as applicable to the affected unit.
    (i) If you operate a coal-fired electric utility steam generating 
unit that burns a blend of coals from different coal ranks or a blend 
of coal and coal refuse, you must not discharge into the atmosphere any 
gases from a new affected source that contain Hg in excess of the 
computed weighted Hg emissions limit based on the Btu, MWh, or MJ 
contributed by each coal rank burned during the compliance period and 
its applicable Hg emissions limit in paragraphs (a)(1) through (4) of 
this section as determined using Equation 1 in this section. For each 
affected source, you must comply with the weighted Hg emissions limit 
calculated using Equation 1 in this section based on the total Hg 
emissions from the unit and the total Btu, MWh, or MJ contributed by 
all fuels burned during the compliance period.

 [GRAPHIC] [TIFF OMITTED] TP09FE07.015


Where:

ELb = Total allowable Hg in lb/MWh that can be emitted to 
the atmosphere from any affected source being averaged according to 
this paragraph.
ELi = Hg emissions limit for the subcategory i (coal 
rank) that applies to affected source, lb/MWh;
HHi = For each affected source, the Btu, MWh, or MJ 
contributed by the corresponding subcategory i (coal rank) burned 
during the compliance period; and
n = Number of subcategories (coal ranks) being averaged for an 
affected source.

    (ii) If you operate a coal-fired electric utility steam generating 
unit that burns a blend of coals from different coal ranks or a blend 
of coal and coal refuse together with one or more non-regulated, 
supplementary fuels, you must not discharge into the atmosphere any 
gases from a new affected source that contain Hg in excess of the 
computed weighted Hg emission limit based on the Btu, MWh, or MJ

[[Page 6342]]

contributed by each coal rank burned during the compliance period and 
its applicable Hg emissions limit in paragraphs (a)(1) through (4) of 
this section as determined using Equation 1 in this section. For each 
affected source, you must comply with the weighted Hg emissions limit 
calculated using Equation 1 in this section based on the total Hg 
emissions from the unit contributed by both regulated and nonregulated 
fuels burned during the compliance period and the total Btu, MWh, or MJ 
contributed by both regulated and nonregulated fuels burned during the 
compliance period.
    (b) For each IGCC electric utility steam generating unit, on and 
after the date on which the initial performance test required to be 
conducted under Sec.  60.8 is completed, no owner or operator subject 
to the provisions of this subpart shall cause to be discharged into the 
atmosphere from any affected facility for which construction, 
modification, or reconstruction commenced after January 30, 2004, any 
gases that contain Hg emissions in excess of 20 x 10-6 lb/
MWh or 0.020 lb/GWh on an output basis. The SI equivalent is 0.0025 ng/
J. This Hg emissions limit is based on a 12-month rolling average basis 
using the procedures in Sec.  60.50Da(h).


Sec.  60.46Da  [Reserved]


Sec.  60.47Da  Commercial demonstration permit.

    (a) An owner or operator of an affected facility proposing to 
demonstrate an emerging technology may apply to the Administrator for a 
commercial demonstration permit. The Administrator will issue a 
commercial demonstration permit in accordance with paragraph (e) of 
this section. Commercial demonstration permits may be issued only by 
the Administrator, and this authority will not be delegated.
    (b) An owner or operator of an affected facility that combusts 
solid solvent refined coal (SRC-I) and who is issued a commercial 
demonstration permit by the Administrator is not subject to the 
SO2 emission reduction requirements under Sec.  60.43Da(c) 
but must, as a minimum, reduce SO2 emissions to 20 percent 
of the potential combustion concentration (80 percent reduction) for 
each 24-hour period of steam generator operation and to less than 520 
ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling average basis.
    (c) An owner or operator of a fluidized bed combustion electric 
utility steam generator (atmospheric or pressurized) who is issued a 
commercial demonstration permit by the Administrator is not subject to 
the SO2 emission reduction requirements under Sec.  
60.43Da(a) but must, as a minimum, reduce SO2 emissions to 
15 percent of the potential combustion concentration (85 percent 
reduction) on a 30-day rolling average basis and to less than 520 ng/J 
(1.20 lb/MMBtu) heat input on a 30-day rolling average basis.
    (d) The owner or operator of an affected facility that combusts 
coal-derived liquid fuel and who is issued a commercial demonstration 
permit by the Administrator is not subject to the applicable 
NOX emission limitation and percent reduction under Sec.  
60.44Da(a) but must, as a minimum, reduce emissions to less than 300 
ng/J (0.70 lb/MMBtu) heat input on a 30-day rolling average basis.
    (e) Commercial demonstration permits may not exceed the following 
equivalent MW electrical generation capacity for any one technology 
category, and the total equivalent MW electrical generation capacity 
for all commercial demonstration plants may not exceed 15,000 MW.

------------------------------------------------------------------------
                                                            Equivalent
                                                            Electrical
            Technology                   Pollutant         Capacity (MW
                                                            electrical
                                                             output)
------------------------------------------------------------------------
Solid solvent refined coal (SCR    SO2.................     6,000-10,000
 I).
Fluidized bed combustion           SO2.................        400-3,000
 (atmospheric).
Fluidized bed combustion           SO2.................        400-1,200
 (pressurized).
Coal liquification...............  NOX.................       750-10,000
                                  --------------------------------------
    Total allowable for all        ....................           15,000
     technologies.
------------------------------------------------------------------------

Sec.  60.48Da  Compliance provisions.

    (a) Compliance with the PM emission limitation under Sec.  
60.42Da(a)(1) constitutes compliance with the percent reduction 
requirements for PM under Sec.  60.42Da(a)(2) and (3).
    (b) Compliance with the NOX emission limitation under 
Sec.  60.44Da(a)(1) constitutes compliance with the percent reduction 
requirements under Sec.  60.44Da(a)(2).
    (c) The PM emission standards under Sec.  60.42Da, the 
NOX emission standards under Sec.  60.44Da, and the Hg 
emission standards under Sec.  60.45Da apply at all times except during 
periods of startup, shutdown, or malfunction.
    (d) During emergency conditions in the principal company, an 
affected facility with a malfunctioning flue gas desulfurization system 
may be operated if SO2 emissions are minimized by:
    (1) Operating all operable flue gas desulfurization system modules, 
and bringing back into operation any malfunctioned module as soon as 
repairs are completed,
    (2) Bypassing flue gases around only those flue gas desulfurization 
system modules that have been taken out of operation because they were 
incapable of any SO2 emission reduction or which would have 
suffered significant physical damage if they had remained in operation, 
and
    (3) Designing, constructing, and operating a spare flue gas 
desulfurization system module for an affected facility larger than 365 
MW (1,250 MMBtu/hr) heat input (approximately 125 MW electrical output 
capacity). The Administrator may at his discretion require the owner or 
operator within 60 days of notification to demonstrate spare module 
capability. To demonstrate this capability, the owner or operator must 
demonstrate compliance with the appropriate requirements under 
paragraph under Sec.  60.43Da(a), (b), (d), (e), and (h) for any period 
of operation lasting from 24 hours to 30 days when:
    (i) Any one flue gas desulfurization module is not operated,
    (ii) The affected facility is operating at the maximum heat input 
rate,
    (iii) The fuel fired during the 24-hour to 30-day period is 
representative of the type and average sulfur content of fuel used over 
a typical 30-day period, and
    (iv) The owner or operator has given the Administrator at least 30 
days notice of the date and period of time over which the demonstration 
will be performed.
    (e) After the initial performance test required under Sec.  60.8, 
compliance with

[[Page 6343]]

the SO2 emission limitations and percentage reduction 
requirements under Sec.  60.43Da and the NOX emission 
limitations under Sec.  60.44Da is based on the average emission rate 
for 30 successive boiler operating days. A separate performance test is 
completed at the end of each boiler operating day after the initial 
performance test, and a new 30 day average emission rate for both 
SO2 and NOX and a new percent reduction for 
SO2 are calculated to show compliance with the standards.
    (f) For the initial performance test required under Sec.  60.8, 
compliance with the SO2 emission limitations and percent 
reduction requirements under Sec.  60.43Da and the NOX 
emission limitation under Sec.  60.44Da is based on the average 
emission rates for SO2, NOX, and percent 
reduction for SO2 for the first 30 successive boiler 
operating days. The initial performance test is the only test in which 
at least 30 days prior notice is required unless otherwise specified by 
the Administrator. The initial performance test is to be scheduled so 
that the first boiler operating day of the 30 successive boiler 
operating days is completed within 60 days after achieving the maximum 
production rate at which the affected facility will be operated, but 
not later than 180 days after initial startup of the facility.
    (g) The owner or operator of an affected facility subject to 
emission limitations in this subpart shall determine compliance as 
follows:
    (1) Compliance with applicable 30-day rolling average 
SO2 and NOX emission limitations is determined by 
calculating the arithmetic average of all hourly emission rates for 
SO2 and NOX for the 30 successive boiler 
operating days, except for data obtained during startup, shutdown, 
malfunction (NOX only), or emergency conditions 
(SO2 only).
    (2) Compliance with applicable SO2 percentage reduction 
requirements is determined based on the average inlet and outlet 
SO2 emission rates for the 30 successive boiler operating 
days.
    (3) Compliance with applicable daily average PM emission 
limitations is determined by calculating the arithmetic average of all 
hourly emission rates for PM each boiler operating day, except for data 
obtained during startup, shutdown, and malfunction. Averages are not 
calculated for boiler operating days with less than 18 hours of valid 
data. Instead, the valid hourly emission rates are averaged with the 
immediately following boiler operating day emission rates to determine 
compliance.
    (h) If an owner or operator has not obtained the minimum quantity 
of emission data as required under Sec.  60.49Da of this subpart, 
compliance of the affected facility with the emission requirements 
under Sec. Sec.  60.43Da and 60.44Da of this subpart for the day on 
which the 30-day period ends may be determined by the Administrator by 
following the applicable procedures in section 7 of Method 19 of 
appendix A of this part.
    (i) Compliance provisions for sources subject to Sec.  
60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f). The owner or 
operator of an affected facility subject to Sec.  60.44Da(d)(1), 
(e)(1), (e)(2)(i), (e)(3)(i), or (f) shall calculate NOX 
emissions by multiplying the average hourly NOX output 
concentration, measured according to the provisions of Sec.  
60.49Da(c), by the average hourly flow rate, measured according to the 
provisions of Sec.  60.49Da(l), and dividing by the average hourly 
gross energy output, measured according to the provisions of Sec.  
60.49Da(k).
    (j) Compliance provisions for duct burners subject to Sec.  
60.44Da(a)(1). To determine compliance with the emissions limits for 
NOX required by Sec.  60.44Da(a) for duct burners used in 
combined cycle systems, either of the procedures described in paragraph 
(j)(1) or (2) of this section may be used:
    (1) The owner or operator of an affected duct burner shall conduct 
the performance test required under Sec.  60.8 using the appropriate 
methods in appendix A of this part. Compliance with the emissions 
limits under Sec.  60.44Da(a)(1) is determined on the average of three 
(nominal 1-hour) runs for the initial and subsequent performance tests. 
During the performance test, one sampling site shall be located in the 
exhaust of the turbine prior to the duct burner. A second sampling site 
shall be located at the outlet from the heat recovery steam generating 
unit. Measurements shall be taken at both sampling sites during the 
performance test; or
    (2) The owner or operator of an affected duct burner may elect to 
determine compliance by using the continuous emission monitoring system 
(CEMS) specified under Sec.  60.49Da for measuring NOX and 
oxygen (O2) and meet the requirements of Sec.  60.49Da. Data 
from a CEMS certified (or recertified) according to the provisions of 
40 CFR 75.20, meeting the QA and QC requirements of 40 CFR 75.21, and 
validated according to 40 CFR 75.23 may be used. The sampling site 
shall be located at the outlet from the steam generating unit. The 
NOX emission rate at the outlet from the steam generating 
unit shall constitute the NOX emission rate from the duct 
burner of the combined cycle system.
    (k) Compliance provisions for duct burners subject to Sec.  
60.44Da(d)(1) or (e)(1). To determine compliance with the emission 
limitation for NOX required by Sec.  60.44Da(d)(1) or (e)(1) 
for duct burners used in combined cycle systems, either of the 
procedures described in paragraphs (k)(1) and (2) of this section may 
be used:
    (1) The owner or operator of an affected duct burner used in 
combined cycle systems shall determine compliance with the applicable 
NOX emission limitation in Sec.  60.44Da(d)(1) or (e)(1) as 
follows:
    (i) The emission rate (E) of NOX shall be computed using 
Equation 2 in this section:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.016


Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross output;
Csg = Average hourly concentration of NOX 
exiting the steam generating unit, ng/dscm (lb/dscf);
Cte = Average hourly concentration of NOX in 
the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of exhaust gas 
from steam generating unit, dscm/hr (dscf/hr);
Qte = Average hourly volumetric flow rate of exhaust gas 
from combustion turbine, dscm/hr (dscf/hr);
Osg = Average hourly gross energy output from steam 
generating unit, J (MWh); and
h = Average hourly fraction of the total heat input to the steam 
generating unit derived from the combustion of fuel in the affected 
duct burner.

    (ii) Method 7E of appendix A of this part shall be used to 
determine the NOX concentrations (Csg and 
Cte). Method 2, 2F or 2G of appendix A of this part, as 
appropriate, shall be used to determine the volumetric flow rates 
(Qsg and Qte) of the exhaust gases. The 
volumetric flow rate measurements shall be taken at the same time as 
the concentration measurements.
    (iii) The owner or operator shall develop, demonstrate, and provide 
information satisfactory to the Administrator to determine the average 
hourly gross energy output from the steam generating unit, and the 
average hourly percentage of the total heat input to the steam 
generating unit derived from the combustion of fuel in the affected 
duct burner.
    (iv) Compliance with the applicable NOX emission 
limitation in Sec.  60.44Da(d)(1) or (e)(1) is determined

[[Page 6344]]

by the three-run average (nominal 1-hour runs) for the initial and 
subsequent performance tests.
    (2) The owner or operator of an affected duct burner used in a 
combined cycle system may elect to determine compliance with the 
applicable NOX emission limitation in Sec.  60.44Da(d)(1) or 
(e)(1) on a 30-day rolling average basis as indicated in paragraphs 
(k)(2)(i) through (iv) of this section.
    (i) The emission rate (E) of NOX shall be computed using 
Equation 3 in this section:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.017


Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross output;
Csg = Average hourly concentration of NOX 
exiting the steam generating unit, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of exhaust gas 
from steam generating unit, dscm/hr (dscf/hr); and
Occ = Average hourly gross energy output from entire 
combined cycle unit, J (MWh).

    (ii) The CEMS specified under Sec.  60.49Da for measuring 
NOX and O2 shall be used to determine the average 
hourly NOX concentrations (Csg). The continuous 
flow monitoring system specified in Sec.  60.49Da(l) shall be used to 
determine the volumetric flow rate (Qsg) of the exhaust gas. 
The sampling site shall be located at the outlet from the steam 
generating unit. Data from a continuous flow monitoring system 
certified (or recertified) following procedures specified in 40 CFR 
75.20, meeting the quality assurance and quality control requirements 
of 40 CFR 75.21, and validated according to 40 CFR 75.23 may be used.
    (iii) The continuous monitoring system specified under Sec.  
60.49Da(k) for measuring and determining gross energy output shall be 
used to determine the average hourly gross energy output from the 
entire combined cycle unit (Occ), which is the combined 
output from the combustion turbine and the steam generating unit.
    (iv) The owner or operator may, in lieu of installing, operating, 
and recording data from the continuous flow monitoring system specified 
in Sec.  60.49Da(l), determine the mass rate (lb/hr) of NOX 
emissions by installing, operating, and maintaining continuous fuel 
flowmeters following the appropriate measurements procedures specified 
in appendix D of part 75 of this chapter. If this compliance option is 
selected, the emission rate (E) of NOX shall be computed 
using Equation 4 in this section:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.018


Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross output;
ERsg = Average hourly emission rate of NOX 
exiting the steam generating unit heat input calculated using 
appropriate F factor as described in Method 19 of appendix A of this 
part, ng/J (lb/MMBtu);
Hcc = Average hourly heat input rate of entire combined 
cycle unit, J/hr (MMBtu/hr); and
Occ = Average hourly gross energy output from entire 
combined cycle unit, J (MWh).

    (3) When an affected duct burner steam generating unit utilizes a 
common steam turbine with one or more affected duct burner steam 
generating units, the owner or operator shall either:
    (i) Determine compliance with the applicable NOX 
emissions limits by measuring the emissions combined with the emissions 
from the other unit(s) utilizing the common steam turbine; or
    (ii) Develop, demonstrate, and provide information satisfactory to 
the Administrator on methods for apportioning the combined gross energy 
output from the steam turbine for each of the affected duct burners. 
The Administrator may approve such demonstrated substitute methods for 
apportioning the combined gross energy output measured at the steam 
turbine whenever the demonstration ensures accurate estimation of 
emissions regulated under this part.
    (l) Compliance provisions for sources subject to Sec.  60.45Da. The 
owner or operator of an affected facility subject to Sec.  60.45Da (new 
sources constructed or reconstructed after January 30, 2004) shall 
calculate the Hg emission rate (lb/MWh) for each calendar month of the 
year, using hourly Hg concentrations measured according to the 
provisions of Sec.  60.49Da(p) in conjunction with hourly stack gas 
volumetric flow rates measured according to the provisions of Sec.  
60.49Da(l) or (m), and hourly gross electrical outputs, determined 
according to the provisions in Sec.  60.49Da(k). Compliance with the 
applicable standard under Sec.  60.45Da is determined on a 12-month 
rolling average basis.
    (m) Compliance provisions for sources subject to Sec.  
60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), or 
(j)(3)(i). The owner or operator of an affected facility subject to 
Sec.  60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i),or 
(j)(3)(i) shall calculate SO2 emissions by multiplying the 
average hourly SO2 output concentration, measured according 
to the provisions of Sec.  60.49Da(b), by the average hourly flow rate, 
measured according to the provisions of Sec.  60.49Da(l), and divided 
by the average hourly gross energy output, measured according to the 
provisions of Sec.  60.49Da(k).
    (n) Compliance provisions for sources subject to Sec.  
60.42Da(c)(1). The owner or operator of an affected facility subject to 
Sec.  60.42Da(c)(1) shall calculate PM emissions by multiplying the 
average hourly PM output concentration, measured according to the 
provisions of Sec.  60.49Da(t), by the average hourly flow rate, 
measured according to the provisions of Sec.  60.49Da(l), and divided 
by the average hourly gross energy output, measured according to the 
provisions of Sec.  60.49Da(k). Compliance with the emission limit is 
determined by calculating the arithmetic average of the hourly emission 
rates computed for each boiler operating day.
    (o) Compliance provisions for sources subject to Sec.  
60.42Da(c)(2) or (d). Except as provided for in paragraph (p) of this 
section, the owner or operator of an affected facility for which 
construction, reconstruction, or modification commenced after February 
28, 2005, shall demonstrate compliance with each applicable emission 
limit according to the requirements in paragraphs (o)(1) through (o)(5) 
of this section.
    (1) Conduct an initial performance test according to the 
requirements in Sec.  60.50Da to demonstrate compliance by the 
applicable date specified in Sec.  60.8(a) and, thereafter, conduct 
subsequent performance test within 365 calendar days of the prior test, 
and
    (2) An owner or operator must use opacity monitoring equipment as 
an indicator of continuous PM control device performance and 
demonstrate compliance with Sec.  60.42Da(b). In addition, baseline 
parameters shall be established as the highest clock hour opacity 
average (average of 10 6-minute measurements) measured by the 
continuous opacity monitoring system during the PM performance test. If 
any clock hour average opacity measurement is more than 110 percent of 
the baseline level, the owner or operator will conduct another 
performance test within 45 operating days to demonstrate compliance. A 
new baseline is established during each PM performance test. The new 
baseline shall not exceed the opacity limit specified in Sec.  
60.42Da(b), and
    (3) An owner or operator using an ESP to comply with the applicable 
emission limits shall use voltage and secondary current monitoring 
equipment to

[[Page 6345]]

measure voltage and secondary current to the ESP. Baseline parameters 
shall be established as average rates measured during the performance 
test. If a 3-hour average voltage and secondary current average 
deviates more than 10 percent from the baseline level, the owner or 
operator will conduct another performance test within 45 operating days 
to demonstrate compliance. A new baseline is established during each PM 
performance test, and
    (4) An owner or operator using a fabric filter to comply with the 
applicable emission limits shall install, calibrate, maintain, and 
continuously operate a bag leak detection system according to 
paragraphs (o)(4)(i) through (viii) of this section.
    (i) Install and operate a bag leak detection system for each 
exhaust stack of the fabric filter.
    (ii) Each bag leak detection system must be installed, operated, 
calibrated, and maintained in a manner consistent with the 
manufacturer's written specifications and recommendations and in 
accordance with the ``Fabric Filter Bag Leak Detection Guidance'' (EPA 
454/R-98-015, September 1997). This document is available from the U.S. 
Environmental Protection Agency (U.S. EPA); Office of Air Quality 
Planning and Standards; Sector Policies and Programs Division; 
Measurement Policy Group (D243-02), Research Triangle Park, NC 27711. 
This document is also available on the Technology Transfer Network 
(TTN) under Emission Measurement Center Continuous Emission Monitoring.
    (iii) The bag leak detection system must be certified by the 
manufacturer to be capable of detecting PM emissions at concentrations 
of 10 milligrams per actual cubic meter or less.
    (iv) The bag leak detection system sensor must provide output of 
relative or absolute PM loadings.
    (v) The bag leak detection system must be equipped with a device to 
continuously record the output signal from the sensor.
    (vi) The bag leak detection system must be equipped with an alarm 
system that will sound automatically when an increase in relative PM 
emissions over a preset level is detected. The alarm must be located 
where it is easily heard by plant operating personnel. Corrective 
actions must be initiated within 1 hour of a bag leak detection system 
alarm. If the alarm is engaged for more than 5 percent of the total 
operating time on a 30-day rolling average basis, a performance test 
must be performed within 45 operating days to demonstrate compliance.
    (vii) For positive pressure fabric filter systems that do not duct 
all compartments of cells to a common stack, a bag leak detection 
system must be installed in each baghouse compartment or cell.
    (viii) Where multiple bag leak detectors are required, the system's 
instrumentation and alarm may be shared among detectors, and
    (5) An owner or operator of a modified affected source electing to 
meet the emission limitations in Sec.  60.42Da(d) shall determine the 
percent reduction in PM by using the emission rate for PM determined by 
the performance test conducted according to the requirements in 
paragraph (o)(1) of this section and the ash content on a mass basis of 
the fuel burned during each performance test run as determined by 
analysis of the fuel as fired.
    (p) As an alternative to meeting the compliance provisions 
specified in paragraph (o) of this section, an owner or operator may 
elect to install, certify, maintain, and operate a CEMS measuring PM 
emissions discharged from the affected facility to the atmosphere and 
record the output of the system as specified in paragraphs (p)(1) 
through (p)(8) of this section.
    (1) The owner or operator shall submit a written notification to 
the Administrator of intent to demonstrate compliance with this subpart 
by using a CEMS measuring PM. This notification shall be sent at least 
30 calendar days before the initial startup of the monitor for 
compliance determination purposes. The owner or operator may 
discontinue operation of the monitor and instead return to 
demonstration of compliance with this subpart according to the 
requirements in paragraph (o) of this section by submitting written 
notification to the Administrator of such intent at least 30 calendar 
days before shutdown of the monitor for compliance determination 
purposes.
    (2) Each CEMS shall be installed, certified, operated, and 
maintained according to the requirements in Sec.  60.49Da(v).
    (3) The initial performance evaluation shall be completed no later 
than 180 days after the date of initial startup of the affected 
facility, as specified under Sec.  60.8 of subpart A of this part or 
within 180 days of the date of notification to the Administrator 
required under paragraph (p)(1) of this section, whichever is later.
    (4) Compliance with the applicable emissions limit shall be 
determined based on the 24-hour daily (block) average of the hourly 
arithmetic average emissions concentrations using the continuous 
monitoring system outlet data. The 24-hour block arithmetic average 
emission concentration shall be calculated using EPA Reference Method 
19 of appendix A of this part, section 4.1.
    (5) At a minimum, valid CEMS hourly averages shall be obtained for 
75 percent of all operating hours on a 30-day rolling average basis. 
Beginning on January 1, 2012, valid CEMS hourly averages shall be 
obtained for 90 percent of all operating hours on a 30-day rolling 
average basis.
    (i) At least two data points per hour shall be used to calculate 
each 1-hour arithmetic average.
    (ii) [Reserved]
    (6) The 1-hour arithmetic averages required shall be expressed in 
ng/J, MMBtu/hr, or lb/MWh and shall be used to calculate the boiler 
operating day daily arithmetic average emission concentrations. The 1-
hour arithmetic averages shall be calculated using the data points 
required under Sec.  60.13(e)(2) of subpart A of this part.
    (7) All valid CEMS data shall be used in calculating average 
emission concentrations even if the minimum CEMS data requirements of 
paragraph (j)(5) of this section are not met.
    (8) When PM emissions data are not obtained because of CEMS 
breakdowns, repairs, calibration checks, and zero and span adjustments, 
emissions data shall be obtained by using other monitoring systems as 
approved by the Administrator or EPA Reference Method 19 of appendix A 
of this part to provide, as necessary, valid emissions data for a 
minimum of 90 percent (only 75 percent is required prior to January 1, 
2012) of all operating hours per 30-day rolling average.


Sec.  60.49Da  Emission monitoring.

    (a) Except as provided for in paragraphs (t) and (u) of this 
section, the owner or operator of an affected facility, shall install, 
calibrate, maintain, and operate a CEMS, and record the output of the 
system, for measuring the opacity of emissions discharged to the 
atmosphere. If opacity interference due to water droplets exists in the 
stack (for example, from the use of an FGD system), the opacity is 
monitored upstream of the interference (at the inlet to the FGD 
system). If opacity interference is experienced at all locations (both 
at the inlet and outlet of the SO2 control system), 
alternate parameters indicative of the PM control system's performance 
and/or good combustion are monitored (subject to the approval of the 
Administrator).

[[Page 6346]]

    (b) The owner or operator of an affected facility shall install, 
calibrate, maintain, and operate a CEMS, and record the output of the 
system, for measuring SO2 emissions, except where natural 
gas is the only fuel combusted, as follows:
    (1) Sulfur dioxide emissions are monitored at both the inlet and 
outlet of the SO2 control device.
    (2) For a facility that qualifies under the numerical limit 
provisions of Sec.  60.43Da(d), (i), (j), or (k) SO2 
emissions are only monitored as discharged to the atmosphere.
    (3) An ``as fired'' fuel monitoring system (upstream of coal 
pulverizers) meeting the requirements of Method 19 of appendix A of 
this part may be used to determine potential SO2 emissions 
in place of a continuous SO2 emission monitor at the inlet 
to the SO2 control device as required under paragraph (b)(1) 
of this section.
    (c)(1) The owner or operator of an affected facility shall install, 
calibrate, maintain, and operate a CEMS, and record the output of the 
system, for measuring NOX emissions discharged to the 
atmosphere; or
    (2) If the owner or operator has installed a NOX 
emission rate CEMS to meet the requirements of part 75 of this chapter 
and is continuing to meet the ongoing requirements of part 75 of this 
chapter, that CEMS may be used to meet the requirements of this 
section, except that the owner or operator shall also meet the 
requirements of Sec.  60.51Da. Data reported to meet the requirements 
of Sec.  60.51Da shall not include data substituted using the missing 
data procedures in subpart D of part 75 of this chapter, nor shall the 
data have been bias adjusted according to the procedures of part 75 of 
this chapter.
    (d) The owner or operator of an affected facility shall install, 
calibrate, maintain, and operate a CEMS, and record the output of the 
system, for measuring the O2 or carbon dioxide 
(CO2) content of the flue gases at each location where 
SO2 or NOX emissions are monitored.
    (e) The CEMS under paragraphs (b), (c), and (d) of this section are 
operated and data recorded during all periods of operation of the 
affected facility including periods of startup, shutdown, malfunction 
or emergency conditions, except for CEMS breakdowns, repairs, 
calibration checks, and zero and span adjustments.
    (f)(1) For units that began construction, reconstruction, or 
modification on or before February 28, 2005, the owner or operator 
shall obtain emission data for at least 18 hours in at least 22 out of 
30 successive boiler operating days. If this minimum data requirement 
cannot be met with CEMS, the owner or operator shall supplement 
emission data with other monitoring systems approved by the 
Administrator or the reference methods and procedures as described in 
paragraph (h) of this section.
    (2) For units that began construction, reconstruction, or 
modification after February 28, 2005, the owner or operator shall 
obtain emission data for at least 90 percent of all operating hours for 
each 30 successive boiler operating days. If this minimum data 
requirement cannot be met with a CEMS, the owner or operator shall 
supplement emission data with other monitoring systems approved by the 
Administrator or the reference methods and procedures as described in 
paragraph (h) of this section.
    (g) The 1-hour averages required under paragraph Sec.  60.13(h) are 
expressed in ng/J (lb/MMBtu) heat input and used to calculate the 
average emission rates under Sec.  60.48Da. The 1-hour averages are 
calculated using the data points required under Sec.  60.13(b). At 
least two data points must be used to calculate the 1-hour averages.
    (h) When it becomes necessary to supplement CEMS data to meet the 
minimum data requirements in paragraph (f) of this section, the owner 
or operator shall use the reference methods and procedures as specified 
in this paragraph. Acceptable alternative methods and procedures are 
given in paragraph (j) of this section.
    (1) Method 6 of appendix A of this part shall be used to determine 
the SO2 concentration at the same location as the 
SO2 monitor. Samples shall be taken at 60-minute intervals. 
The sampling time and sample volume for each sample shall be at least 
20 minutes and 0.020 dscm (0.71 dscf). Each sample represents a 1-hour 
average.
    (2) Method 7 of appendix A of this part shall be used to determine 
the NOX concentration at the same location as the 
NOX monitor. Samples shall be taken at 30-minute intervals. 
The arithmetic average of two consecutive samples represents a 1-hour 
average.
    (3) The emission rate correction factor, integrated bag sampling 
and analysis procedure of Method 3B of appendix A of this part shall be 
used to determine the O2 or CO2 concentration at 
the same location as the O2 or CO2 monitor. 
Samples shall be taken for at least 30 minutes in each hour. Each 
sample represents a 1-hour average.
    (4) The procedures in Method 19 of appendix A of this part shall be 
used to compute each 1-hour average concentration in ng/J (1b/MMBtu) 
heat input.
    (i) The owner or operator shall use methods and procedures in this 
paragraph to conduct monitoring system performance evaluations under 
Sec.  60.13(c) and calibration checks under Sec.  60.13(d). Acceptable 
alternative methods and procedures are given in paragraph (j) of this 
section.
    (1) Methods 3B, 6, and 7 of appendix A of this part shall be used 
to determine O2, SO2, and NOX 
concentrations, respectively.
    (2) SO2 or NOX (NO), as applicable, shall be 
used for preparing the calibration gas mixtures (in N2, as 
applicable) under Performance Specification 2 of appendix B of this 
part.
    (3) For affected facilities burning only fossil fuel, the span 
value for a CEMS for measuring opacity is between 60 and 80 percent and 
for a CEMS measuring NOX is determined as follows:

------------------------------------------------------------------------
             Fossil fuel                   Span values for  NOX (ppm)
------------------------------------------------------------------------
Gas..................................  500
Liquid...............................  500
Solid................................  1,000
Combination..........................  500(x + y) + 1,000z
------------------------------------------------------------------------

    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 (i)(3) of this section 
for burning combinations of fossil fuels are rounded to the nearest 500 
ppm.
    (5) For affected facilities burning fossil fuel, alone or in 
combination with non-fossil fuel, the span value of the SO2 
CEMS at the inlet to the SO2 control device is 125 percent 
of the maximum estimated hourly potential emissions of the fuel fired, 
and the outlet of the SO2 control device is 50 percent of 
maximum estimated hourly potential emissions of the fuel fired.
    (j) The owner or operator may use the following as alternatives to 
the reference methods and procedures specified in this section:
    (1) For Method 6 of appendix A of this part, Method 6A or 6B 
(whenever Methods 6 and 3 or 3B of appendix A of this part data are 
used) or 6C of appendix A of this part may be used. Each Method 6B of 
appendix A of this part sample obtained over 24 hours represents 24 1-
hour averages. If Method 6A or 6B of appendix A of this part is used 
under paragraph (i) of this section, the conditions under Sec.  
60.48Da(d)(1)

[[Page 6347]]

apply; these conditions do not apply under paragraph (h) of this 
section.
    (2) 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 1 hour.
    (3) For Method 3 of appendix A of this part, Method 3A or 3B of 
appendix A of this part may be used if the sampling time is 1 hour.
    (4) For Method 3B of appendix A of this part, Method 3A of appendix 
A of this part may be used.
    (k) The procedures specified in paragraphs (k)(1) through (3) of 
this section shall be used to determine gross output for sources 
demonstrating compliance with the output-based standard under Sec.  
60.44Da(d)(1).
    (1) The owner or operator of an affected facility with electricity 
generation shall install, calibrate, maintain, and operate a wattmeter; 
measure gross electrical output in MWh on a continuous basis; and 
record the output of the monitor.
    (2) The owner or operator of an affected facility with process 
steam generation shall install, calibrate, maintain, and operate meters 
for steam flow, temperature, and pressure; measure gross process steam 
output in joules per hour (or Btu per hour) on a continuous basis; and 
record the output of the monitor.
    (3) For affected facilities generating process steam in combination 
with electrical generation, the gross energy output is determined from 
the gross electrical output measured in accordance with paragraph 
(k)(1) of this section plus 75 percent of the gross thermal output 
(measured relative to ISO conditions) of the process steam measured in 
accordance with paragraph (k)(2) of this section.
    (l) The owner or operator of an affected facility demonstrating 
compliance with an output-based standard under Sec.  60.42Da, Sec.  
60.43Da, Sec.  60.44Da, or Sec.  60.45Da shall install, certify, 
operate, and maintain a continuous flow monitoring system meeting the 
requirements of Performance Specification 6 of appendix B and procedure 
1 of appendix F of this part, and record the output of the system, for 
measuring the flow of exhaust gases discharged to the atmosphere; or
    (m) Alternatively, data from a continuous flow monitoring system 
certified according to the requirements of 40 CFR 75.20, meeting the 
applicable quality control and quality assurance requirements of 40 CFR 
75.21, and validated according to appendix B of part 75 of this 
chapter, may be used.
    (n) Gas-fired and oil-fired units. The owner or operator of an 
affected unit that qualifies as a gas-fired or oil-fired unit, as 
defined in 40 CFR 72.2, may use, as an alternative to the requirements 
specified in either paragraph (l) or (m) of this section, a fuel flow 
monitoring system certified and operated according to the requirements 
of appendix D of part 75 of this chapter.
    (o) The owner or operator of a duct burner, as described in Sec.  
60.41Da, which is subject to the NOX standards of Sec.  
60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate 
a CEMS to measure NOX emissions; a wattmeter to measure 
gross electrical output; meters to measure steam flow, temperature, and 
pressure; and a continuous flow monitoring system to measure the flow 
of exhaust gases discharged to the atmosphere.
    (p) The owner or operator of an affected facility demonstrating 
compliance with an Hg limit in Sec.  60.45Da shall install and operate 
a CEMS to measure and record the concentration of Hg in the exhaust 
gases from each stack according to the requirements in paragraphs 
(p)(1) through (p)(3) of this section. Alternatively, for an affected 
facility that is also subject to the requirements of subpart I of part 
75 of this chapter, the owner or operator may install, certify, 
maintain, operate and quality-assure the data from a Hg CEMS according 
to Sec.  75.10 of this chapter and appendices A and B to part 75 of 
this chapter, in lieu of following the procedures in paragraphs (p)(1) 
through (p)(3) of this section.
    (1) The owner or operator must install, operate, and maintain each 
CEMS according to Performance Specification 12A in appendix B to this 
part.
    (2) The owner or operator must conduct a performance evaluation of 
each CEMS according to the requirements of Sec.  60.13 and Performance 
Specification 12A in appendix B to this part.
    (3) The owner or operator must operate each CEMS according to the 
requirements in paragraphs (p)(3)(i) through (iv) of this section.
    (i) As specified in Sec.  60.13(e)(2), each CEMS must complete a 
minimum of one cycle of operation (sampling, analyzing, and data 
recording) for each successive 15-minute period.
    (ii) The owner or operator must reduce CEMS data as specified in 
Sec.  60.13(h).
    (iii) The owner or operator shall use all valid data points 
collected during the hour to calculate the hourly average Hg 
concentration.
    (iv) The owner or operator must record the results of each required 
certification and quality assurance test of the CEMS.
    (4) Mercury CEMS data collection must conform to paragraphs 
(p)(4)(i) through (iv) of this section.
    (i) For each calendar month in which the affected unit operates, 
valid hourly Hg concentration data, stack gas volumetric flow rate 
data, moisture data (if required), and electrical output data (i.e., 
valid data for all of these parameters) shall be obtained for at least 
75 percent of the unit operating hours in the month.
    (ii) Data reported to meet the requirements of this subpart shall 
not include hours of unit startup, shutdown, or malfunction. In 
addition, for an affected facility that is also subject to subpart I of 
part 75 of this chapter, data reported to meet the requirements of this 
subpart shall not include data substituted using the missing data 
procedures in subpart D of part 75 of this chapter, nor shall the data 
have been bias adjusted according to the procedures of part 75 of this 
chapter.
    (iii) If valid data are obtained for less than 75 percent of the 
unit operating hours in a month, you must discard the data collected in 
that month and replace the data with the mean of the individual monthly 
emission rate values determined in the last 12 months. In the 12-month 
rolling average calculation, this substitute Hg emission rate shall be 
weighted according to the number of unit operating hours in the month 
for which the data capture requirement of Sec.  60.49Da(p)(4)(i) was 
not met.
    (iv) Notwithstanding the requirements of paragraph (p)(4)(iii) of 
this section, if valid data are obtained for less than 75 percent of 
the unit operating hours in another month in that same 12-month rolling 
average cycle, discard the data collected in that month and replace the 
data with the highest individual monthly emission rate determined in 
the last 12 months. In the 12-month rolling average calculation, this 
substitute Hg emission rate shall be weighted according to the number 
of unit operating hours in the month for which the data capture 
requirement of Sec.  60.49Da(p)(4)(i) was not met.
    (q) As an alternative to the CEMS required in paragraph (p) of this 
section, the owner or operator may use a sorbent trap monitoring system 
(as defined in Sec.  72.2 of this chapter) to monitor Hg concentration, 
according to the procedures described in Sec.  75.15 of this

[[Page 6348]]

chapter and appendix K to part 75 of this chapter.
    (r) For Hg CEMS that measure Hg concentration on a dry basis or for 
sorbent trap monitoring systems, the emissions data must be corrected 
for the stack gas moisture content. A certified continuous moisture 
monitoring system that meets the requirements of Sec.  75.11(b) of this 
chapter is acceptable for this purpose. Alternatively, the appropriate 
default moisture value, as specified in Sec.  75.11(b) or Sec.  
75.12(b) of this chapter, may be used.
    (s) The owner or operator shall prepare and submit to the 
Administrator for approval a unit-specific monitoring plan for each 
monitoring system, at least 45 days before commencing certification 
testing of the monitoring systems. The owner or operator shall comply 
with the requirements in your plan. The plan must address the 
requirements in paragraphs (s)(1) through (6) of this section.
    (1) Installation of the CEMS sampling probe or other interface at a 
measurement location relative to each affected process unit such that 
the measurement is representative of the exhaust emissions (e.g., on or 
downstream of the last control device);
    (2) Performance and equipment specifications for the sample 
interface, the pollutant concentration or parametric signal analyzer, 
and the data collection and reduction systems;
    (3) Performance evaluation procedures and acceptance criteria 
(e.g., calibrations, relative accuracy test audits (RATA), etc.);
    (4) Ongoing operation and maintenance procedures in accordance with 
the general requirements of Sec.  60.13(d) or part 75 of this chapter 
(as applicable);
    (5) Ongoing data quality assurance procedures in accordance with 
the general requirements of Sec.  60.13 or part 75 of this chapter (as 
applicable); and
    (6) Ongoing recordkeeping and reporting procedures in accordance 
with the requirements of this subpart.
    (t) The owner or operator of an affected facility demonstrating 
compliance with the output-based emissions limitation under Sec.  
60.42Da(c)(1) shall install, certify, operate, and maintain a CEMS for 
measuring PM emissions according to the requirements of paragraph (v) 
of this section. An owner or operator of an affected source 
demonstrating compliance with the input-based emission limitation under 
Sec.  60.42Da(c)(2) may install, certify, operate, and maintain a CEMS 
for measuring PM emissions according to the requirements of paragraph 
(v) of this section.
    (u) An owner or operator of an affected source that meets the 
conditions in either paragraph (u)(1) or (2) of this section is 
exempted from the continuous opacity monitoring system requirements in 
paragraph (a) of this section and the monitoring requirements in Sec.  
60.48Da(o).
    (1) A CEMS for measuring PM emissions is used to demonstrate 
continuous compliance on a boiler operating day average with the 
emissions limitations under Sec.  60.42Da(a)(1) or Sec.  60.42Da(c)(2) 
and is installed, certified, operated, and maintained on the affected 
source according to the requirements of paragraph (v) of this section; 
or
    (2) The affected source burns only gaseous fuels and does not use a 
post combustion technology to reduce emissions of SO2 or PM.
    (v) The owner or operator of an affected facility using a CEMS 
measuring PM emissions to meet requirements of this subpart shall 
install, certify, operate, and maintain the CEMS as specified in 
paragraphs (v)(1) through (v)(3).
    (1) The owner or operator shall conduct a performance evaluation of 
the CEMS according to the applicable requirements of Sec.  60.13, 
Performance Specification 11 in appendix B of this part, and procedure 
2 in appendix F of this part.
    (2) During each relative accuracy test run of the CEMS required by 
Performance Specification 11 in appendix B of this part, PM and 
O2 (or CO2) data shall be collected concurrently 
(or within a 30-to 60-minute period) by both the CEMS and conducting 
performance tests using the following test methods.
    (i) For PM, EPA Reference Method 5, 5B, or 17 of appendix A of this 
part shall be used.
    (ii) For O2 (or CO2), EPA Reference Method 3, 
3A, or 3B of appendix A of this part, as applicable, shall be used.
    (3) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with procedure 2 in appendix F 
of this part. Relative Response Audits must be performed annually and 
Response Correlation Audits must be performed every 3 years.


Sec.  60.50Da  Compliance determination procedures and methods.

    (a) In conducting the performance tests required in Sec.  60.8, the 
owner or operator shall use as reference methods and procedures the 
methods in appendix A of this part or the methods and procedures as 
specified in this section, except as provided in Sec.  60.8(b). Section 
60.8(f) does not apply to this section for SO2 and 
NOX. Acceptable alternative methods are given in paragraph 
(e) of this section.
    (b) The owner or operator shall determine compliance with the PM 
standards in Sec.  60.42Da as follows:
    (1) The dry basis F factor (O2) procedures in Method 19 
of appendix A of this part shall be used to compute the emission rate 
of PM.
    (2) For the particular matter concentration, Method 5 of appendix A 
of this part shall be used at affected facilities without wet FGD 
systems and Method 5B of appendix A of this part shall be used after 
wet FGD systems.
    (i) The sampling time and sample volume for each run shall be at 
least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder 
heating system in the sampling train may be set to provide an average 
gas temperature of no greater than 160  14 [deg]C (320 
 25 [deg]F).
    (ii) For each particulate run, the emission rate correction factor, 
integrated or grab sampling and analysis procedures of Method 3B of 
appendix A of this part shall be used to determine the O2 
concentration. The O2 sample shall be obtained 
simultaneously with, and at the same traverse points as, the 
particulate run. 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. 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.
    (3) Method 9 of appendix A of this part and the procedures in Sec.  
60.11 shall be used to determine opacity.
    (c) The owner or operator shall determine compliance with the 
SO2 standards in Sec.  60.43Da as follows:
    (1) The percent of potential SO2 emissions (%Ps) to the 
atmosphere shall be computed using the following equation: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.019

Where:

%Ps = Percent of potential SO2 emissions, 
percent;
%Rf = Percent reduction from fuel pretreatment, percent; 
and
%Rg = Percent reduction by SO2 control system, 
percent.

    (2) The procedures in Method 19 of appendix A of this part may be 
used to determine percent reduction (%Rf) of

[[Page 6349]]

sulfur by such processes as fuel pretreatment (physical coal cleaning, 
hydrodesulfurization of fuel oil, etc.), coal pulverizers, and bottom 
and fly ash interactions. This determination is optional.
    (3) The procedures in Method 19 of appendix A of this part shall be 
used to determine the percent SO2 reduction (%Rg) 
of any SO2 control system. Alternatively, a combination of 
an ``as fired'' fuel monitor and emission rates measured after the 
control system, following the procedures in Method 19 of appendix A of 
this part, may be used if the percent reduction is calculated using the 
average emission rate from the SO2 control device and the 
average SO2 input rate from the ``as fired'' fuel analysis 
for 30 successive boiler operating days.
    (4) The appropriate procedures in Method 19 of appendix A of this 
part shall be used to determine the emission rate.
    (5) The CEMS in Sec.  60.49Da(b) and (d) shall be used to determine 
the concentrations of SO2 and CO2 or 
O2.
    (d) The owner or operator shall determine compliance with the 
NOX standard in Sec.  60.44Da as follows:
    (1) The appropriate procedures in Method 19 of appendix A of this 
part shall be used to determine the emission rate of NOX.
    (2) The continuous monitoring system in Sec.  60.49Da(c) and (d) 
shall be used to determine the concentrations of NOX and 
CO2 or O2.
    (e) The owner or operator may use the following as alternatives to 
the reference methods and procedures specified in this section:
    (1) 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 temperature at the sampling location does not 
exceed an average temperature of 160[deg]C (320[deg]F). The procedures 
of Sec. Sec.  2.1 and 2.3 of Method 5B of appendix A of this part may 
be used in 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 is saturated or laden 
with water droplets.
    (2) The Fc factor (CO2) procedures in Method 
19 of appendix A of this part may be used to compute the emission rate 
of PM under the stipulations of Sec.  60.46(d)(1). The CO2 
shall be determined in the same manner as the O2 
concentration.
    (f) Electric utility combined cycle gas turbines are performance 
tested for PM, SO2, and NOX using the procedures 
of Method 19 of appendix A of this part. The SO2 and 
NOX emission rates from the gas turbine used in Method 19 of 
appendix A of this part calculations are determined when the gas 
turbine is performance tested under subpart GG of this part. The 
potential uncontrolled PM emission rate from a gas turbine is defined 
as 17 ng/J (0.04 lb/MMBtu) heat input.
    (g) For the purposes of determining compliance with the emission 
limits in Sec.  60.45Da, the owner or operator of an electric utility 
steam generating unit which is also a cogeneration unit shall use the 
procedures in paragraphs (g)(1) and (2) of this section to calculate 
emission rates based on electrical output to the grid plus 75 percent 
of the equivalent electrical energy (measured relative to ISO 
conditions) in the unit's process stream.
    (1) All conversions from Btu/hr unit input to MW unit output must 
use equivalents found in 40 CFR 60.40(a)(1) for electric utilities 
(i.e., 250 MMBtu/hr input to an electric utility steam generating unit 
is equivalent to 73 MW input to the electric utility steam generating 
unit); 73 MW input to the electric utility steam generating unit is 
equivalent to 25 MW output from the boiler electric utility steam 
generating unit; therefore, 250 MMBtu input to the electric utility 
steam generating unit is equivalent to 25 MW output from the electric 
utility steam generating unit).
    (2) Use the Equation 5 in this section to determine the 
cogeneration Hg emission rate over a specific compliance period. 
[GRAPHIC] [TIFF OMITTED] TP09FE07.020

Where:

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

    (h) The owner or operator shall determine compliance with the Hg 
limit in Sec.  60.45Da according to the procedures in paragraphs (h)(1) 
through (3) of this section.
    (1) The initial performance test shall be commenced by the 
applicable date specified in Sec.  60.8(a). The required CEMS must be 
certified prior to commencing the test. The performance test consists 
of collecting hourly Hg emission data (lb/MWh) with the CEMS for 12 
successive months of unit operation (excluding hours of unit startup, 
shutdown and malfunction). The average Hg emission rate is calculated 
for each month, and then the weighted, 12-month average Hg emission 
rate is calculated according to paragraph (h)(2) or (h)(3) of this 
section, as applicable. If, for any month in the initial performance 
test, the minimum data capture requirement in Sec.  60.49Da(p)(4)(i) is 
not met, the owner or operator shall report a substitute Hg emission 
rate for that month, as follows. For the first such month, the 
substitute monthly Hg emission rate shall be the arithmetic average of 
all valid hourly Hg emission rates recorded to date. For any subsequent 
month(s) with insufficient data capture, the substitute monthly Hg 
emission rate shall be the highest valid hourly Hg emission rate 
recorded to date. When the 12-month average Hg emission rate for the 
initial performance test is calculated, for each month in which there 
was insufficient data capture, the substitute monthly Hg emission rate 
shall be weighted according to the number of unit operating hours in 
that month. Following the initial performance test, the owner or 
operator shall demonstrate compliance by calculating the weighted 
average of all monthly Hg emission rates (in lb/MWh) for each 12 
successive calendar months, excluding data obtained during startup, 
shutdown, or malfunction.
    (2) If a CEMS is used to demonstrate compliance, follow the 
procedures in paragraphs (h)(2)(i) through (iii) of this section to 
determine the 12-month rolling average.
    (i) Calculate the total mass of Hg emissions over a month (M), in 
lb, using either Equation 6 in paragraph (h)(2)(i)(A) of this section 
or Equation 7 in paragraph (h)(2)(i)(B) of this section, in conjunction 
with Equation 8 in paragraph (h)(2)(i)(C) of this section.
    (A) If the Hg CEMS measures Hg concentration on a wet basis, use 
Equation 6 below to calculate the Hg mass emissions for each valid 
hour: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.021

Where:

Eh = Hg mass emissions for the hour, (lb);
K = Units conversion constant, 6.24 x 10-11 lb-scm/
[mu]gm-scf;
Ch = Hourly Hg concentration, wet basis, ([mu]gm/scm);
Qh = Hourly stack gas volumetric flow rate, (scfh); and
th = Unit operating time, i.e., the fraction of the hour 
for which the unit operated. For example, th = 0.50 for a 
half-hour of unit operation and 1.00 for a full hour of operation.

    (B) If the Hg CEMS measures Hg concentration on a dry basis, use

[[Page 6350]]

Equation 7 below to calculate the Hg mass emissions for each valid 
hour: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.022

Where:

Eh = Hg mass emissions for the hour, (lb);
K = Units conversion constant, 6.24 x 10-11 lb-scm/
[mu]gm-scf;
Ch = Hourly Hg concentration, dry basis, ([mu]gm/dscm);
Qh = Hourly stack gas volumetric flow rate, (scfh);
th = Unit operating time, i.e., the fraction of the hour 
for which the unit operated; and
Bws = Stack gas moisture content, expressed as a decimal 
fraction (e.g., for 8 percent H2O, Bws = 
0.08).

    (C) Use Equation 8, below, to calculate M, the total mass of Hg 
emitted for the month, by summing the hourly masses derived from 
Equation 6 or 7 (as applicable): 
[GRAPHIC] [TIFF OMITTED] TP09FE07.023

Where:

M = Total Hg mass emissions for the month, (lb);
Eh = Hg mass emissions for hour ``h'', from Equation 6 or 
7 of this section, (lb); and
n = Number of unit operating hours in the month with valid CE and 
electrical output data, excluding hours of unit startup, shutdown 
and malfunction.

    (ii) Calculate the monthly Hg emission rate on an output basis (lb/
MWh) using Equation 9, below. For a cogeneration unit, use Equation 5 
in paragraph (g) of this section instead. 
[GRAPHIC] [TIFF OMITTED] TP09FE07.024

Where:

ER = Monthly Hg emission rate, (lb/MWh);
M = Total mass of Hg emissions for the month, from Equation 8, 
above, (lb); and
P = Total electrical output for the month, for the hours used to 
calculate M, (MWh).

    (iii) Until 12 monthly Hg emission rates have been accumulated, 
calculate and report only the monthly averages. Then, for each 
subsequent calendar month, use Equation 10 below to calculate the 12-
month rolling average as a weighted average of the Hg emission rate for 
the current month and the Hg emission rates for the previous 11 months, 
with one exception. Calendar months in which the unit does not operate 
(zero unit operating hours) shall not be included in the 12-month 
rolling average. 
[GRAPHIC] [TIFF OMITTED] TP09FE07.025

Where:

Eavg = Weighted 12-month rolling average Hg emission 
rate, (lb/MWh);
ERi = Monthly Hg emission rate, for month ``i'', (lb/
MWh); and
n = Number of unit operating hours in month ``i'' with valid CEM and 
electrical output data, excluding hours of unit startup, shutdown, 
and malfunction.

    (3) If a sorbent trap monitoring system is used in lieu of a Hg 
CEMS, as described in Sec.  75.15 of this chapter and in appendix K to 
part 75 of this chapter, calculate the monthly Hg emission rates using 
Equations 7 through 9 of this section, except that for a particular 
pair of sorbent traps, Ch in Equation 7 shall be the flow-
proportional average Hg concentration measured over the data collection 
period.
    (i) Daily calibration drift (CD) tests and quarterly accuracy 
determinations shall be performed for Hg CEMS in accordance with 
Procedure 1 of appendix F to this part. For the CD assessments, you may 
use either elemental mercury or mercuric chloride (Hg[deg] or 
HgCl2) standards. The four quarterly accuracy determinations 
shall consist of one RATA and three measurement error (ME) tests using 
HgCl2 standards, as described in section 8.3 of Performance 
Specification 12-A in appendix B to this part (note: Hg[deg] standards 
may be used if the Hg monitor does not have a converter). 
Alternatively, the owner or operator may implement the applicable 
daily, weekly, quarterly, and annual quality assurance (QA) 
requirements for Hg CEMS in appendix B to part 75 of this chapter, in 
lieu of the QA procedures in appendices B and F to this part. Annual 
RATA of sorbent trap monitoring systems shall be performed in 
accordance with appendices A and B to part 75 of this chapter, and all 
other quality assurance requirements specified in appendix K to part 75 
of this chapter shall be met for sorbent trap monitoring systems.


Sec.  60.51Da  Reporting requirements.

    (a) For SO2, NOX, PM, and Hg emissions, the 
performance test data from the initial and subsequent performance test 
and from the performance evaluation of the continuous monitors 
(including the transmissometer) are submitted to the Administrator.
    (b) For SO2 and NOX the following information 
is reported to the Administrator for each 24-hour period.
    (1) Calendar date.
    (2) The average SO2 and NOX emission rates 
(ng/J or lb/MMBtu) for each 30 successive boiler operating days, ending 
with the last 30-day period in the quarter; reasons for non-compliance 
with the emission standards; and, description of corrective actions 
taken.
    (3) Percent reduction of the potential combustion concentration of 
SO2 for each 30 successive boiler operating days, ending 
with the last 30-day period in the quarter; reasons for non-compliance 
with the standard; and, description of corrective actions taken.
    (4) Identification of the boiler operating days for which pollutant 
or diluent data have not been obtained by an approved method for at 
least 75 percent of the hours of operation of the facility; 
justification for not obtaining sufficient data; and description of 
corrective actions taken.
    (5) Identification of the times when emissions data have been 
excluded from the calculation of average emission rates because of 
startup, shutdown, malfunction (NOX only), emergency 
conditions (SO2 only), or other reasons, and justification 
for excluding data for reasons other than startup, shutdown, 
malfunction, or emergency conditions.
    (6) Identification of ``F'' factor used for calculations, method of 
determination, and type of fuel combusted.
    (7) Identification of times when hourly averages have been obtained 
based on manual sampling methods.
    (8) Identification of the times when the pollutant concentration 
exceeded full span of the CEMS.
    (9) Description of any modifications to CEMS which could affect the 
ability of the CEMS to comply with Performance Specifications 2 or 3.
    (c) If the minimum quantity of emission data as required by Sec.  
60.49Da is not obtained for any 30 successive boiler operating days, 
the following information obtained under the requirements of Sec.  
60.48Da(h) is reported to the Administrator for that 30-day period:
    (1) The number of hourly averages available for outlet emission 
rates (no) and inlet emission rates (ni) as 
applicable.
    (2) The standard deviation of hourly averages for outlet emission 
rates (so) and inlet emission rates (si) as 
applicable.
    (3) The lower confidence limit for the mean outlet emission rate 
(Eo*) and the

[[Page 6351]]

upper confidence limit for the mean inlet emission rate 
(Ei*) as applicable.
    (4) The applicable potential combustion concentration.
    (5) The ratio of the upper confidence limit for the mean outlet 
emission rate (Eo*) and the allowable emission rate 
(Estd) as applicable.
    (d) If any standards under Sec.  60.43Da are exceeded during 
emergency conditions because of control system malfunction, the owner 
or operator of the affected facility shall submit a signed statement:
    (1) Indicating if emergency conditions existed and requirements 
under Sec.  60.48Da(d) were met during each period, and
    (2) Listing the following information:
    (i) Time periods the emergency condition existed;
    (ii) Electrical output and demand on the owner or operator's 
electric utility system and the affected facility;
    (iii) Amount of power purchased from interconnected neighboring 
utility companies during the emergency period;
    (iv) Percent reduction in emissions achieved;
    (v) Atmospheric emission rate (ng/J) of the pollutant discharged; 
and
    (vi) Actions taken to correct control system malfunction.
    (e) If fuel pretreatment credit toward the SO2 emission 
standard under Sec.  60.43Da is claimed, the owner or operator of the 
affected facility shall submit a signed statement:
    (1) Indicating what percentage cleaning credit was taken for the 
calendar quarter, and whether the credit was determined in accordance 
with the provisions of Sec.  60.50Da and Method 19 of appendix A of 
this part; and
    (2) Listing the quantity, heat content, and date each pretreated 
fuel shipment was received during the previous quarter; the name and 
location of the fuel pretreatment facility; and the total quantity and 
total heat content of all fuels received at the affected facility 
during the previous quarter.
    (f) For any periods for which opacity, SO2 or 
NOX emissions data are not available, the owner or operator 
of the affected facility shall submit a signed statement indicating if 
any changes were made in operation of the emission control system 
during the period of data unavailability. Operations of the control 
system and affected facility during periods of data unavailability are 
to be compared with operation of the control system and affected 
facility before and following the period of data unavailability.
    (g) For Hg, the following information shall be reported to the 
Administrator:
    (1) Company name and address;
    (2) Date of report and beginning and ending dates of the reporting 
period;
    (3) The applicable Hg emission limit (lb/MWh); and
    (4) For each month in the reporting period:
    (i) The number of unit operating hours;
    (ii) The number of unit operating hours with valid data for Hg 
concentration, stack gas flow rate, moisture (if required), and 
electrical output;
    (iii) The monthly Hg emission rate (lb/MWh);
    (iv) The number of hours of valid data excluded from the 
calculation of the monthly Hg emission rate, due to unit startup, 
shutdown and malfunction; and
    (v) The 12-month rolling average Hg emission rate (lb/MWh); and
    (5) The data assessment report (DAR) required by appendix F to this 
part, or an equivalent summary of QA test results if the QA of part 75 
of this chapter are implemented.
    (h) The owner or operator of the affected facility shall submit a 
signed statement indicating whether:
    (1) The required CEMS calibration, span, and drift checks or other 
periodic audits have or have not been performed as specified.
    (2) The data used to show compliance was or was not obtained in 
accordance with approved methods and procedures of this part and is 
representative of plant performance.
    (3) The minimum data requirements have or have not been met; or, 
the minimum data requirements have not been met for errors that were 
unavoidable.
    (4) Compliance with the standards has or has not been achieved 
during the reporting period.
    (i) For the purposes of the reports required under Sec.  60.7, 
periods of excess emissions are defined as all 6-minute periods during 
which the average opacity exceeds the applicable opacity standards 
under Sec.  60.42Da(b). Opacity levels in excess of the applicable 
opacity standard and the date of such excesses are to be submitted to 
the Administrator each calendar quarter.
    (j) The owner or operator of an affected facility shall submit the 
written reports required under this section and subpart A to the 
Administrator semiannually for each six-month period. All semiannual 
reports shall be postmarked by the 30th day following the end of each 
six-month period.
    (k) The owner or operator of an affected facility may submit 
electronic quarterly reports for SO2 and/or NOX 
and/or opacity and/or Hg in lieu of submitting the written reports 
required under paragraphs (b), (g), and (i) of this section. The format 
of each quarterly electronic report shall be coordinated with the 
permitting authority. The electronic report(s) shall be submitted no 
later than 30 days after the end of the calendar quarter and shall be 
accompanied by a certification statement from the owner or operator, 
indicating whether compliance with the applicable emission standards 
and minimum data requirements of this subpart was achieved during the 
reporting period. Before submitting reports in the electronic format, 
the owner or operator shall coordinate with the permitting authority to 
obtain their agreement to submit reports in this alternative format.


Sec.  60.52Da  Recordkeeping requirements.

    The owner or operator of an affected facility subject to the 
emissions limitations in Sec.  60.45Da shall provide notifications in 
accordance with Sec.  60.7(a) and shall maintain records of all 
information needed to demonstrate compliance including performance 
tests, monitoring data, fuel analyses, and calculations, consistent 
with the requirements of Sec.  60.7(f).

Subpart Db--[Amended]

    5. Subpart Db is revised to read as follows:

Subpart Db--Standards of Performance for Industrial-Commercial-
Institutional Steam Generating Units

Sec.
60.40b Applicability and delegation of authority.
60.41b Definitions.
60.42b Standard for sulfur dioxide (SO2).
60.43b Standard for particulate matter (PM).
60.44b Standard for nitrogen oxides (NOX).
60.45b Compliance and performance test methods and procedures for 
sulfur dioxide.
60.46b Compliance and performance test methods and procedures for 
particulate matter and nitrogen oxides.
60.47b Emission monitoring for sulfur dioxide.
60.48b Emission monitoring for particulate matter and nitrogen 
oxides.
60.49b Reporting and recordkeeping requirements.

Subpart Db--Standards of Performance for Industrial-Commercial-
Institutional Steam Generating Units


Sec.  60.40b  Applicability and delegation of authority.

    (a) The affected facility to which this subpart applies is each 
steam generating unit that commences construction, modification, or 
reconstruction after

[[Page 6352]]

June 19, 1984, and that has a heat input capacity from fuels combusted 
in the steam generating unit of greater than 29 megawatts (MW) (100 
million British thermal units per hour (MMBtu/hr)).
    (b) Any affected facility meeting the applicability requirements 
under paragraph (a) of this section and commencing construction, 
modification, or reconstruction after June 19, 1984, but on or before 
June 19, 1986, is subject to the following standards:
    (1) Coal-fired affected facilities having a heat input capacity 
between 29 and 73 MW (100 and 250 MMBtu/hr), inclusive, are subject to 
the particulate matter (PM) and nitrogen oxides (NOX) 
standards under this subpart.
    (2) Coal-fired affected facilities having a heat input capacity 
greater than 73 MW (250 MMBtu/hr) and meeting the applicability 
requirements under subpart D (Standards of performance for fossil-fuel-
fired steam generators; Sec.  60.40) are subject to the PM and 
NOX standards under this subpart and to the sulfur dioxide 
(SO2) standards under subpart D (Sec.  60.43).
    (3) Oil-fired affected facilities having a heat input capacity 
between 29 and 73 MW (100 and 250 MMBtu/hr), inclusive, are subject to 
the NOX standards under this subpart.
    (4) Oil-fired affected facilities having a heat input capacity 
greater than 73 MW (250 MMBtu/hr) and meeting the applicability 
requirements under subpart D (Standards of performance for fossil-fuel-
fired steam generators; Sec.  60.40) are also subject to the 
NOX standards under this subpart and the PM and 
SO2 standards under subpart D (Sec.  60.42 and Sec.  60.43).
    (c) Affected facilities that also meet the applicability 
requirements under subpart J (Standards of performance for petroleum 
refineries; Sec.  60.104) are subject to the PM and NOX 
standards under this subpart and the SO2 standards under 
subpart J (Sec.  60.104).
    (d) Affected facilities that also meet the applicability 
requirements under subpart E (Standards of performance for 
incinerators; Sec.  60.50) are subject to the NOX and PM 
standards under this subpart.
    (e) Steam generating units meeting the applicability requirements 
under subpart Da (Standards of performance for electric utility steam 
generating units; Sec.  60.40Da) are not subject to this subpart.
    (f) Any change to an existing steam generating unit for the sole 
purpose of combusting gases containing total reduced sulfur (TRS) as 
defined under Sec.  60.281 is not considered a modification under Sec.  
60.14 and the steam generating unit is not subject to this subpart.
    (g) In delegating implementation and enforcement authority to a 
State under section 111(c) of the Clean Air Act, the following 
authorities shall be retained by the Administrator and not transferred 
to a State.
    (1) Section 60.44b(f).
    (2) Section 60.44b(g).
    (3) Section 60.49b(a)(4).
    (h) Any affected facility that meets the applicability requirements 
and is subject to subpart Ea, subpart Eb, or subpart AAAA of this part 
is not covered by this subpart.
    (i) Heat recovery steam generators that are associated with 
combined cycle gas turbines and that meet the applicability 
requirements of subpart GG or KKKK of this part are not subject to this 
subpart. This subpart will continue to apply to all other heat recovery 
steam generators that are capable of combusting more than 29 MW (100 
MMBtu/hr) heat input of fossil fuel. If the heat recovery steam 
generator is subject to this subpart, only emissions resulting from 
combustion of fuels in the steam generating unit are subject to this 
subpart. (The gas turbine emissions are subject to subpart GG or KKKK, 
as applicable, of this part.)
    (j) Any affected facility meeting the applicability requirements 
under paragraph (a) of this section and commencing construction, 
modification, or reconstruction after June 19, 1986 is not subject to 
subpart D (Standards of Performance for Fossil-Fuel-Fired Steam 
Generators, Sec.  60.40).
    (k) Any affected facility that meets the applicability requirements 
and is subject to an EPA approved State or Federal section 111(d)/129 
plan implementing subpart Cb or subpart BBBB of this part is not 
covered by this subpart.


Sec.  60.41b  Definitions.

    As used in this subpart, all terms not defined herein shall have 
the meaning given them in the Clean Air Act and in subpart A of this 
part.
    Annual capacity factor means the ratio between the actual heat 
input to a steam generating unit from the fuels listed in Sec.  
60.42b(a), Sec.  60.43b(a), or Sec.  60.44b(a), as applicable, during a 
calendar year and the potential heat input to the steam generating unit 
had it been operated for 8,760 hours during a calendar year at the 
maximum steady state design heat input capacity. In the case of steam 
generating units that are rented or leased, the actual heat input shall 
be determined based on the combined heat input from all operations of 
the affected facility in a calendar year.
    Byproduct/waste means any liquid or gaseous substance produced at 
chemical manufacturing plants, petroleum refineries, or pulp and paper 
mills (except natural gas, distillate oil, or residual oil) and 
combusted in a steam generating unit for heat recovery or for disposal. 
Gaseous substances with carbon dioxide (CO2) levels greater 
than 50 percent or carbon monoxide levels greater than 10 percent are 
not byproduct/waste for the purpose of this subpart.
    Chemical manufacturing plants mean industrial plants that are 
classified by the Department of Commerce under Standard Industrial 
Classification (SIC) Code 28.
    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), 
coal refuse, and petroleum coke. Coal-derived synthetic fuels, 
including but not limited to solvent refined coal, gasified coal, coal-
oil mixtures, coke oven gas, and coal-water mixtures, are also included 
in this definition for the purposes of this subpart.
    Coal refuse means any byproduct of coal mining or coal cleaning 
operations with an ash content greater than 50 percent, by weight, and 
a heating value less than 13,900 kJ/kg (6,000 Btu/lb) on a dry basis.
    Cogeneration, also known as combined heat and power, means a 
facility that simultaneously produces both electric (or mechanical) and 
useful thermal energy from the same primary energy source.
    Coke oven gas means the volatile constituents generated in the 
gaseous exhaust during the carbonization of bituminous coal to form 
coke.
    Combined cycle system means a system in which a separate source, 
such as a gas turbine, internal combustion engine, kiln, etc., provides 
exhaust gas to a steam generating unit.
    Conventional technology means wet flue gas desulfurization (FGD) 
technology, dry FGD technology, atmospheric fluidized bed combustion 
technology, and oil hydrodesulfurization technology.
    Distillate oil means fuel oils that contain 0.05 weight percent 
nitrogen or less and comply with the specifications for fuel oil 
numbers 1 and 2, as defined by the American Society of Testing and 
Materials in ASTM D396 (incorporated by reference, see Sec.  60.17).
    Dry flue gas desulfurization technology means a SO2 
control system that is located downstream of the steam generating unit 
and removes sulfur oxides from the combustion gases of the

[[Page 6353]]

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 flue gas desulfurization 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 steam generating unit.
    Emerging technology means any SO2 control system that is 
not defined as a conventional technology under this section, and for 
which the owner or operator of the facility has applied to the 
Administrator and received approval to operate as an emerging 
technology under Sec.  60.49b(a)(4).
    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.
    Fluidized bed combustion technology means combustion of fuel in a 
bed or series of beds (including but not limited to bubbling bed units 
and circulating bed units) of limestone aggregate (or other sorbent 
materials) in which these materials are forced upward by the flow of 
combustion air and the gaseous products of combustion.
    Fuel pretreatment means a process that removes a portion of the 
sulfur in a fuel before combustion of the fuel in a steam generating 
unit.
    Full capacity means operation of the steam generating unit at 90 
percent or more of the maximum steady-state design heat input capacity.
    Gaseous fuel means any fuel that is present as a gas at ISO 
conditions.
    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).
    Heat input means heat derived from combustion of fuel in a steam 
generating unit and does not include the heat derived from preheated 
combustion air, recirculated flue gases, or exhaust gases from other 
sources, such as gas turbines, internal combustion engines, kilns, etc.
    Heat release rate means the steam generating unit design heat input 
capacity (in MW or Btu/hr) divided by the furnace volume (in cubic 
meters or cubic feet); the furnace volume is that volume bounded by the 
front furnace wall where the burner is located, the furnace side 
waterwall, and extending to the level just below or in front of the 
first row of convection pass tubes.
    Heat transfer medium means any material that is used to transfer 
heat from one point to another point.
    High heat release rate means a heat release rate greater than 
730,000 J/sec-m3 (70,000 Btu/hr-ft3).
    ISO Conditions means a temperature of 288 Kelvin, a relative 
humidity of 60 percent, and a pressure of 101.3 kilopascals.
    Lignite means a type of coal classified as lignite A or lignite B 
by the American Society of Testing and Materials in ASTM D388 
(incorporated by reference, see Sec.  60.17).
    Low heat release rate means a heat release rate of 730,000 J/sec-
m3 (70,000 Btu/hr-ft3) or less.
    Mass-feed stoker steam generating unit means a steam generating 
unit where solid fuel is introduced directly into a retort or is fed 
directly onto a grate where it is combusted.
    Maximum heat input capacity means the ability of a steam generating 
unit to combust a stated maximum amount of fuel on a steady state 
basis, as determined by the physical design and characteristics of the 
steam generating unit.
    Municipal-type solid waste means refuse, more than 50 percent of 
which is waste consisting of a mixture of paper, wood, yard wastes, 
food wastes, plastics, leather, rubber, and other combustible 
materials, and noncombustible materials such as glass and rock.
    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) 
liquefied petroleum gas, as defined by the American Society for Testing 
and Materials in ASTM D1835 (incorporated by reference, see Sec.  
60.17).
    Noncontinental area means the State of Hawaii, the Virgin Islands, 
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern 
Mariana Islands.
    Oil means crude oil or petroleum or a liquid fuel derived from 
crude oil or petroleum, including distillate and residual oil.
    Petroleum refinery means industrial plants as classified by the 
Department of Commerce under Standard Industrial Classification (SIC) 
Code 29.
    Potential sulfur dioxide emission rate means the theoretical 
SO2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat 
input) that would result from combusting fuel in an uncleaned state and 
without using emission control systems.
    Process heater means a device that is primarily used to heat a 
material to initiate or promote a chemical reaction in which the 
material participates as a reactant or catalyst.
    Pulp and paper mills means industrial plants that are classified by 
the Department of Commerce under North American Industry Classification 
System (NAICS) Code 322 or Standard Industrial Classification (SIC) 
Code 26.
    Pulverized coal-fired steam generating unit means a steam 
generating unit in which pulverized coal is introduced into an air 
stream that carries the coal to the combustion chamber of the steam 
generating unit where it is fired in suspension. This includes both 
conventional pulverized coal-fired and micropulverized coal-fired steam 
generating units.
    Residual oil means crude oil, fuel oil numbers 1 and 2 that have a 
nitrogen content greater than 0.05 weight percent, and all fuel oil 
numbers 4, 5 and 6, as defined by the American Society of Testing and 
Materials in ASTM D396 (incorporated by reference, see Sec.  60.17).
    Spreader stoker steam generating unit means a steam generating unit 
in which solid fuel is introduced to the combustion zone by a mechanism 
that throws the fuel onto a grate from above. Combustion takes place 
both in suspension and on the grate.
    Steam generating unit means a device that combusts any fuel or 
byproduct/waste and produces steam or heats water or any other heat 
transfer medium. This term includes any municipal-type solid waste 
incinerator with a heat recovery steam generating unit or any steam 
generating unit that combusts fuel and is part of a cogeneration system 
or a combined cycle system. This term does not include process heaters 
as they are defined in this subpart.
    Steam generating unit operating day means a 24-hour period between 
12:00 midnight and the following midnight during which any fuel is 
combusted at any time in the steam generating unit.

[[Page 6354]]

It is not necessary for fuel to be combusted continuously for the 
entire 24-hour period.
    Very low sulfur oil means for units constructed, reconstructed, or 
modified on or before February 28, 2005, an oil that contains no more 
than 0.5 weight percent sulfur or that, when combusted without 
SO2 emission control, has a SO2 emission rate 
equal to or less than 215 ng/J (0.5 lb/MMBtu) heat input. For units 
constructed, reconstructed, or modified after February 28, 2005, very 
low sulfur oil means an oil that contains no more than 0.3 weight 
percent sulfur or that, when combusted without SO2 emission 
control, has a SO2 emission rate equal to or less than 140 
ng/J (0.32 lb/MMBtu) heat input.
    Wet flue gas desulfurization technology means a SO2 
control system that is located downstream of the steam generating unit 
and removes sulfur oxides from the combustion gases of the steam 
generating unit by contacting the combustion gas with an alkaline 
slurry or solution and forming a liquid material. This definition 
applies to devices where the aqueous liquid material product of this 
contact is subsequently converted to other forms. Alkaline reagents 
used in wet flue gas desulfurization technology include, but are not 
limited to, lime, limestone, and sodium.
    Wet scrubber system means any emission control device that mixes an 
aqueous stream or slurry with the exhaust gases from a steam generating 
unit to control emissions of PM or SO2.
    Wood means wood, wood residue, bark, or any derivative fuel or 
residue thereof, in any form, including, but not limited to, sawdust, 
sanderdust, wood chips, scraps, slabs, millings, shavings, and 
processed pellets made from wood or other forest residues.


Sec.  60.42b  Standard for sulfur dioxide (SO2).

    (a) Except as provided in paragraphs (b), (c), (d), or (k) of this 
section, on and after the date on which the performance test is 
completed or required to be completed under Sec.  60.8, whichever comes 
first, no owner or operator of an affected facility that commenced 
construction, reconstruction, or modification on or before February 28, 
2005, that combusts coal or oil shall cause to be discharged into the 
atmosphere any gases that contain SO2 in excess of 87 ng/J 
(0.20 lb/MMBtu) or 10 percent (0.10) of the potential SO2 
emission rate (90 percent reduction) and the emission limit determined 
according to the following formula: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.026

Where:

Es = SO2 emission limit, in ng/J or lb/MM Btu 
heat input;
Ka = 520 ng/J (or 1.2 lb/MMBtu);
Kb = 340 ng/J (or 0.80 lb/MMBtu);
Ha = Heat input from the combustion of coal, in J (MMBtu); 
and
Hb = Heat input from the combustion of oil, in J (MMBtu).

    Only the heat input supplied to the affected facility from the 
combustion of coal and oil is counted under this section. No credit is 
provided for the heat input to the affected facility from the 
combustion of natural gas, wood, municipal-type solid waste, or other 
fuels or heat derived from exhaust gases from other sources, such as 
gas turbines, internal combustion engines, kilns, etc.
    (b) On and after the date on which the performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that 
commenced construction, reconstruction, or modification on or before 
February 28, 2005, that combusts coal refuse alone in a fluidized bed 
combustion steam generating unit shall cause to be discharged into the 
atmosphere any gases that contain SO2 in excess of 87 ng/J 
(0.20 lb/MMBtu) or 20 percent (0.20) of the potential SO2 
emission rate (80 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat 
input. If coal or oil is fired with coal refuse, the affected facility 
is subject to paragraph (a) or (d) of this section, as applicable.
    (c) On and after the date on which the performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
comes first, no owner or operator of an affected facility that combusts 
coal or oil, either alone or in combination with any other fuel, and 
that uses an emerging technology for the control of SO2 
emissions, shall cause to be discharged into the atmosphere any gases 
that contain SO2 in excess of 50 percent of the potential 
SO2 emission rate (50 percent reduction) and that contain 
SO2 in excess of the emission limit determined according to 
the following formula: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.027

Where:

Es = SO2 emission limit, in ng/J or lb/MMBtu 
heat input;
Kc = 260 ng/J (or 1.2 lb/MMBtu);
Kd = 170 ng/J (or 0.80 lb/MMBtu);
Hc = Heat input from the combustion of coal, in J 
(MMBtu); and
Hd = Heat input from the combustion of oil, in J (MMBtu).

    Only the heat input supplied to the affected facility from the 
combustion of coal and oil is counted under this section. No credit is 
provided for the heat input to the affected facility from the 
combustion of natural gas, wood, municipal-type solid waste, or other 
fuels, or from the heat input derived from exhaust gases from other 
sources, such as gas turbines, internal combustion engines, kilns, etc.
    (d) On and after the date on which the performance test is 
completed or required to be completed under Sec.  60.8, whichever comes 
first, no owner or operator of an affected facility that commenced 
construction, reconstruction, or modification on or before February 28, 
2005 and listed in paragraphs (d)(1), (2), (3), or (4) of this section 
shall cause to be discharged into the atmosphere any gases that contain 
SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the 
affected facility combusts coal, or 215 ng/J (0.5 lb/MMBtu) heat input 
if the affected facility combusts oil other than very low sulfur oil. 
Percent reduction requirements are not applicable to affected 
facilities under paragraphs (d)(1), (2), (3) or (4) of this section.
    (1) Affected facilities that have an annual capacity factor for 
coal and oil of 30 percent (0.30) or less and are subject to a 
federally enforceable permit limiting the operation of the affected 
facility to an annual capacity factor for coal and oil of 30 percent 
(0.30) or less;
    (2) Affected facilities located in a noncontinental area; or
    (3) Affected facilities combusting coal or oil, alone or in 
combination with any fuel, in a duct burner as part of a combined cycle 
system where 30 percent (0.30) or less of the heat entering the steam 
generating unit is from combustion of coal and oil in the duct burner 
and 70 percent (0.70) or more of the heat entering the steam generating 
unit is from the exhaust gases entering the duct burner; or
    (4) The affected facility burns coke oven gas alone or in 
combination with natural gas or very low sulfur distillate oil.
    (e) Except as provided in paragraph (f) of this section, compliance 
with the emission limits, fuel oil sulfur limits, and/or percent 
reduction requirements under this section are determined on a 30-day 
rolling average basis.
    (f) Except as provided in paragraph (j)(2) of this section, 
compliance with the emission limits or fuel oil sulfur limits under 
this section is determined on a 24-hour average basis for affected

[[Page 6355]]

facilities that (1) have a federally enforceable permit limiting the 
annual capacity factor for oil to 10 percent or less, (2) combust only 
very low sulfur oil, and (3) do not combust any other fuel.
    (g) Except as provided in paragraph (i) of this section, the 
SO2 emission limits and percent reduction requirements under 
this section apply at all times, including periods of startup, 
shutdown, and malfunction.
    (h) Reductions in the potential SO2 emission rate 
through fuel pretreatment are not credited toward the percent reduction 
requirement under paragraph (c) of this section unless:
    (1) Fuel pretreatment results in a 50 percent or greater reduction 
in potential SO2 emissions and
    (2) Emissions from the pretreated fuel (without combustion or post 
combustion SO2 control) are equal to or less than the 
emission limits specified in paragraph (c) of this section.
    (i) An affected facility subject to paragraph (a), (b), or (c) of 
this section may combust very low sulfur oil or natural gas when the 
SO2 control system is not being operated because of 
malfunction or maintenance of the SO2 control system.
    (j) Percent reduction requirements are not applicable to affected 
facilities combusting only very low sulfur oil. The owner or operator 
of an affected facility combusting very low sulfur oil shall 
demonstrate that the oil meets the definition of very low sulfur oil 
by: (1) Following the performance testing procedures as described in 
Sec.  60.45b(c) or Sec.  60.45b(d), and following the monitoring 
procedures as described in Sec.  60.47b(a) or Sec.  60.47b(b) to 
determine SO2 emission rate or fuel oil sulfur content; or 
(2) maintaining fuel records as described in Sec.  60.49b(r).
    (k)(1) Except as provided in paragraphs (k)(2), (k)(3), and (k)(4) 
of this section, on and after the date on which the initial performance 
test is completed or is required to be completed under Sec.  60.8, 
whichever date comes first, no owner or operator of an affected 
facility that commences construction, reconstruction, or modification 
after February 28, 2005, and that combusts coal, oil, natural gas, a 
mixture of these fuels, or a mixture of these fuels with any other 
fuels shall cause to be discharged into the atmosphere any gases that 
contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input 
or 8 percent (0.08) of the potential SO2 emission rate (92 
percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input.
    (2) Units firing only very low sulfur oil and/or a mixture of 
gaseous fuels with a potential SO2 emission rate of 140 ng/J 
(0.32 lb/MMBtu) heat input or less are exempt from the SO2 
emissions limit in paragraph 60.42b(k)(1).
    (3) Units that are located in a noncontinental area and that 
combust coal or oil shall not discharge any gases that contain 
SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the 
affected facility combusts coal, or 215 ng/J (0.50 lb/MMBtu) heat input 
if the affected facility combusts oil.
    (4) As an alternative to meeting the requirements under paragraph 
(k)(1) of this section, modified facilities that combust coal or a 
mixture of coal with other fuels shall not cause to be discharged into 
the atmosphere any gases that contain SO2 in excess of 87 
ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential 
SO2 emission rate (90 percent reduction) and 520 ng/J (1.2 
lb/MMBtu) heat input.


Sec.  60.43b  Standard for particulate matter (PM).

    (a) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
comes first, no owner or operator of an affected facility that 
commenced construction, reconstruction, or modification on or before 
February 28, 2005 that combusts coal or combusts mixtures of coal with 
other fuels, shall cause to be discharged into the atmosphere from that 
affected facility any gases that contain PM in excess of the following 
emission limits:
    (1) 22 ng/J (0.051 lb/MMBtu) heat input,
    (i) If the affected facility combusts only coal, or
    (ii) If the affected facility combusts coal and other fuels and has 
an annual capacity factor for the other fuels of 10 percent (0.10) or 
less.
    (2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility 
combusts coal and other fuels and has an annual capacity factor for the 
other fuels greater than 10 percent (0.10) and is subject to a 
federally enforceable requirement limiting operation of the affected 
facility to an annual capacity factor greater than 10 percent (0.10) 
for fuels other than coal.
    (3) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility 
combusts coal or coal and other fuels and
    (i) Has an annual capacity factor for coal or coal and other fuels 
of 30 percent (0.30) or less,
    (ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or 
less,
    (iii) Has a federally enforceable requirement limiting operation of 
the affected facility to an annual capacity factor of 30 percent (0.30) 
or less for coal or coal and other solid fuels, and
    (iv) Construction of the affected facility commenced after June 19, 
1984, and before November 25, 1986.
    (4) An affected facility burning coke oven gas alone or in 
combination with other fuels not subject to a PM standard under Sec.  
60.43b and not using a post combustion technology (except a wet 
scrubber) for reducing PM or SO2 emissions is not subject to 
the PM limits under Sec.  60.43b(a).
    (b) On and after the date on which the performance test is 
completed or required to be completed under Sec.  60.8, whichever comes 
first, no owner or operator of an affected facility that commenced 
construction, reconstruction, or modification on or before February 28, 
2005, and that combusts oil (or mixtures of oil with other fuels) and 
uses a conventional or emerging technology to reduce SO2 
emissions shall cause to be discharged into the atmosphere from that 
affected facility any gases that contain PM in excess of 43 ng/J (0.10 
lb/MMBtu) heat input.
    (c) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
comes first, no owner or operator of an affected facility that 
commenced construction, reconstruction, or modification on or before 
February 28, 2005, and that combusts wood, or wood with other fuels, 
except coal, shall cause to be discharged from that affected facility 
any gases that contain PM in excess of the following emission limits:
    (1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has 
an annual capacity factor greater than 30 percent (0.30) for wood.
    (2) 86 ng/J (0.20 lb/MMBtu) heat input if
    (i) The affected facility has an annual capacity factor of 30 
percent (0.30) or less for wood;
    (ii) Is subject to a federally enforceable requirement limiting 
operation of the affected facility to an annual capacity factor of 30 
percent (0.30) or less for wood; and
    (iii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or 
less.
    (d) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
combusts municipal-type solid waste or mixtures of municipal-type solid 
waste with other fuels, shall cause to be discharged into the 
atmosphere from that affected facility any gases that

[[Page 6356]]

contain PM in excess of the following emission limits:
    (1) 43 ng/J (0.10 lb/MMBtu) heat input;
    (i) If the affected facility combusts only municipal-type solid 
waste; or
    (ii) If the affected facility combusts municipal-type solid waste 
and other fuels and has an annual capacity factor for the other fuels 
of 10 percent (0.10) or less.
    (2) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility 
combusts municipal-type solid waste or municipal-type solid waste and 
other fuels; and
    (i) Has an annual capacity factor for municipal-type solid waste 
and other fuels of 30 percent (0.30) or less;
    (ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or 
less;
    (iii) Has a federally enforceable requirement limiting operation of 
the affected facility to an annual capacity factor of 30 percent (0.30) 
or less for municipal-type solid waste, or municipal-type solid waste 
and other fuels; and
    (iv) Construction of the affected facility commenced after June 19, 
1984, but on or before November 25, 1986.
    (e) For the purposes of this section, the annual capacity factor is 
determined by dividing the actual heat input to the steam generating 
unit during the calendar year from the combustion of coal, wood, or 
municipal-type solid waste, and other fuels, as applicable, by the 
potential heat input to the steam generating unit if the steam 
generating unit had been operated for 8,760 hours at the maximum heat 
input capacity.
    (f) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
combusts coal, oil, wood, or mixtures of these fuels with any other 
fuels shall cause to be discharged into the atmosphere any gases that 
exhibit greater than 20 percent opacity (6-minute average), except for 
one 6-minute period per hour of not more than 27 percent opacity.
    (g) The PM and opacity standards apply at all times, except during 
periods of startup, shutdown or malfunction. (h)(1) Except as provided 
in paragraphs (h)(2), (h)(3), (h)(4), and (h)(5) of this section, on 
and after the date on which the initial performance test is completed 
or is required to be completed under Sec.  60.8, whichever date comes 
first, no owner or operator of an affected facility that commenced 
construction, reconstruction, or modification after February 28, 2005, 
and that combusts coal, oil, wood, a mixture of these fuels, or a 
mixture of these fuels with any other fuels shall cause to be 
discharged into the atmosphere from that affected facility any gases 
that contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input,
    (2) As an alternative to meeting the requirements of paragraph 
(h)(1) of this section, the owner or operator of an affected facility 
for which modification commenced after February 28, 2005, may elect to 
meet the requirements of this paragraph. On and after the date on which 
the initial performance test is completed or required to be completed 
under Sec.  60.8, no owner or operator of an affected facility that 
commences modification after February 28, 2005 shall cause to be 
discharged into the atmosphere from that affected facility any gases 
that contain PM in excess of both:
    (i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion 
of coal, oil, wood, a mixture of these fuels, or a mixture of these 
fuels with any other fuels; and
    (ii) 0.2 percent of the combustion concentration (99.8 percent 
reduction) when combusting coal, oil, wood, a mixture of these fuels, 
or a mixture of these fuels with any other fuels.
    (3) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
commences modification after February 28, 2005, and that combusts over 
30 percent wood (by heat input) on an annual basis and has a maximum 
heat input capacity of 73 MW (250 MMBtu/h) or less shall cause to be 
discharged into the atmosphere from that affected facility any gases 
that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
    (4) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
commences modification after February 28, 2005, and that combusts over 
30 percent wood (by heat input) on an annual basis and has a maximum 
heat input capacity greater than 73 MW (250 MMBtu/h) shall cause to be 
discharged into the atmosphere from that affected facility any gases 
that contain PM in excess of 37 ng/J (0.085 lb/MMBtu) heat input.
    (5) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
commences construction, reconstruction, or modification after February 
28, 2005, and that combusts only oil that contains no more than 0.3 
weight percent sulfur, coke oven gas, a mixture of these fuels, or 
either fuel (or a mixture of these fuels) in combination with other 
fuels not subject to a PM standard under Sec.  60.43b and not using a 
post combustion technology (except a wet scrubber) to reduce 
SO2 or PM emissions is subject to the PM limits under Sec.  
60.43b(h)(1).


Sec.  60.44b  Standard for nitrogen oxides (NOX).

    (a) Except as provided under paragraphs (k) and (l) of this 
section, on and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that is 
subject to the provisions of this section and that combusts only coal, 
oil, or natural gas shall cause to be discharged into the atmosphere 
from that affected facility any gases that contain NOX 
(expressed as NO2) in excess of the following emission 
limits:

------------------------------------------------------------------------
                                                 Nitrogen Oxide Emission
                                                  Limits (expressed as
        Fuel/steam generating unit type              NO2) Heat Input
                                               -------------------------
                                                    ng/J       lb/MMBtu
------------------------------------------------------------------------
(1) Natural gas and distillate oil, except
 (4):
    (i) Low heat release rate.................           43         0.10
    (ii) High heat release rate...............           86         0.20
(2) Residual oil:
    (i) Low heat release rate.................          130         0.30
    (ii) High heat release rate...............          170         0.40
(3) Coal:

[[Page 6357]]


    (i) Mass-feed stoker......................          210         0.50
    (ii) Spreader stoker and fluidized bed              260         0.60
     combustion...............................
    (iii) Pulverized coal.....................          300         0.70
    (iv) Lignite, except (v)..................          260         0.60
    (v) Lignite mined in North Dakota, South            340         0.80
     Dakota, or Montana and combusted in a
     slag tap furnace.........................
    (vi) Coal-derived synthetic fuels.........          210         0.50
(4) Duct burner used in a combined cycle
 system:
    (i) Low heat release rate.................           86         0.20
    (ii) High heat release rate 43............          170         0.40
------------------------------------------------------------------------

    (b) Except as provided under paragraphs (k) and (l) of this 
section, on and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
simultaneously combusts mixtures of coal, oil, or natural gas shall 
cause to be discharged into the atmosphere from that affected facility 
any gases that contain NOX in excess of a limit determined 
by the use of the following formula: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.028

Where:

En = NOX emission limit (expressed as 
NO2), ng/J (lb/MMBtu);
ELgo = Appropriate emission limit from paragraph (a)(1) 
for combustion of natural gas or distillate oil, ng/J (lb/MMBtu);
Hgo = Heat input from combustion of natural gas or 
distillate oil, J (MMBtu);
ELro = Appropriate emission limit from paragraph (a)(2) 
for combustion of residual oil, ng/J (lb/MMBtu);
Hro = Heat input from combustion of residual oil, J 
(MMBtu);
ELc = Appropriate emission limit from paragraph (a)(3) 
for combustion of coal, ng/J (lb/MMBtu); and
Hc = Heat input from combustion of coal, J (MMBtu).

    (c) Except as provided under paragraph (l) of this section, on and 
after the date on which the initial performance test is completed or is 
required to be completed under Sec.  60.8, whichever date comes first, 
no owner or operator of an affected facility that simultaneously 
combusts coal or oil, or a mixture of these fuels with natural gas, and 
wood, municipal-type solid waste, or any other fuel shall cause to be 
discharged into the atmosphere any gases that contain NOX in 
excess of the emission limit for the coal or oil, or mixtures of these 
fuels with natural gas combusted in the affected facility, as 
determined pursuant to paragraph (a) or (b) of this section, unless the 
affected facility has an annual capacity factor for coal or oil, or 
mixture of these fuels with natural gas of 10 percent (0.10) or less 
and is subject to a federally enforceable requirement that limits 
operation of the affected facility to an annual capacity factor of 10 
percent (0.10) or less for coal, oil, or a mixture of these fuels with 
natural gas.
    (d) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
simultaneously combusts natural gas with wood, municipal-type solid 
waste, or other solid fuel, except coal, shall cause to be discharged 
into the atmosphere from that affected facility any gases that contain 
NOX in excess of 130 ng/J (0.30 lb/MMBtu) heat input unless 
the affected facility has an annual capacity factor for natural gas of 
10 percent (0.10) or less and is subject to a federally enforceable 
requirement that limits operation of the affected facility to an annual 
capacity factor of 10 percent (0.10) or less for natural gas.
    (e) Except as provided under paragraph (l) of this section, on and 
after the date on which the initial performance test is completed or is 
required to be completed under Sec.  60.8, whichever date comes first, 
no owner or operator of an affected facility that simultaneously 
combusts coal, oil, or natural gas with byproduct/waste shall cause to 
be discharged into the atmosphere any gases that contain NOX 
in excess of the emission limit determined by the following formula 
unless the affected facility has an annual capacity factor for coal, 
oil, and natural gas of 10 percent (0.10) or less and is subject to a 
federally enforceable requirement that limits operation of the affected 
facility to an annual capacity factor of 10 percent (0.10) or less: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.029

Where:

    En = NOX emission limit (expressed as 
NO2), ng/J (lb/MMBtu);
ELgo = Appropriate emission limit from paragraph (a)(1) 
for combustion of natural gas or distillate oil, ng/J (lb/MMBtu);
Hgo = Heat input from combustion of natural gas, 
distillate oil and gaseous byproduct/waste, J (MMBtu);
ELro = Appropriate emission limit from paragraph (a)(2) 
for combustion of residual oil and/or byproduct/waste, ng/J (lb/
MMBtu);
Hro = Heat input from combustion of residual oil, J 
(MMBtu);
ELc = Appropriate emission limit from paragraph (a)(3) 
for combustion of coal, ng/J (lb/MMBtu); and
Hc = Heat input from combustion of coal, J (MMBtu).

    (f) Any owner or operator of an affected facility that combusts 
byproduct/waste with either natural gas or oil may petition the 
Administrator within 180 days of the initial startup of the affected 
facility to establish a NOX emission limit that shall apply 
specifically to that affected facility when the byproduct/waste is 
combusted. The petition shall include sufficient and appropriate data, 
as determined by the Administrator, such as NOX emissions 
from the affected facility, waste composition (including nitrogen 
content), and combustion conditions to allow the Administrator to 
confirm that the affected facility is unable to comply with the 
emission limits in paragraph (e) of this section and to determine the 
appropriate emission limit for the affected facility.
    (1) Any owner or operator of an affected facility petitioning for a 
facility-specific NOX emission limit under this section 
shall:
    (i) Demonstrate compliance with the emission limits for natural gas 
and distillate oil in paragraph (a)(1) of this section or for residual 
oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, by 
conducting a 30-day performance test as provided in Sec.  60.46b(e). 
During the performance test only natural gas, distillate oil, or

[[Page 6358]]

residual oil shall be combusted in the affected facility; and
    (ii) Demonstrate that the affected facility is unable to comply 
with the emission limits for natural gas and distillate oil in 
paragraph (a)(1) of this section or for residual oil in paragraph 
(a)(2) or (l)(1) of this section, as appropriate, when gaseous or 
liquid byproduct/waste is combusted in the affected facility under the 
same conditions and using the same technological system of emission 
reduction applied when demonstrating compliance under paragraph 
(f)(1)(i) of this section.
    (2) The NOX emission limits for natural gas or 
distillate oil in paragraph (a)(1) of this section or for residual oil 
in paragraph (a)(2) or (l)(1) of this section, as appropriate, shall be 
applicable to the affected facility until and unless the petition is 
approved by the Administrator. If the petition is approved by the 
Administrator, a facility-specific NOX emission limit will 
be established at the NOX emission level achievable when the 
affected facility is combusting oil or natural gas and byproduct/waste 
in a manner that the Administrator determines to be consistent with 
minimizing NOX emissions. In lieu of amending this subpart, 
a letter will be sent to the facility describing the facility-specific 
NOX limit. The facility shall use the compliance procedures 
detailed in the letter and make the letter available to the public. If 
the Administrator determines it is appropriate, the conditions and 
requirements of the letter can be reviewed and changed at any point.
    (g) Any owner or operator of an affected facility that combusts 
hazardous waste (as defined by 40 CFR part 261 or 40 CFR part 761) with 
natural gas or oil may petition the Administrator within 180 days of 
the initial startup of the affected facility for a waiver from 
compliance with the NOX emission limit that applies 
specifically to that affected facility. The petition must include 
sufficient and appropriate data, as determined by the Administrator, on 
NOX emissions from the affected facility, waste destruction 
efficiencies, waste composition (including nitrogen content), the 
quantity of specific wastes to be combusted and combustion conditions 
to allow the Administrator to determine if the affected facility is 
able to comply with the NOX emission limits required by this 
section. The owner or operator of the affected facility shall 
demonstrate that when hazardous waste is combusted in the affected 
facility, thermal destruction efficiency requirements for hazardous 
waste specified in an applicable federally enforceable requirement 
preclude compliance with the NOX emission limits of this 
section. The NOX emission limits for natural gas or 
distillate oil in paragraph (a)(1) of this section or for residual oil 
in paragraph (a)(2) or (l)(1) of this section, as appropriate, are 
applicable to the affected facility until and unless the petition is 
approved by the Administrator. (See 40 CFR 761.70 for regulations 
applicable to the incineration of materials containing polychlorinated 
biphenyls (PCB's).) In lieu of amending this subpart, a letter will be 
sent to the facility describing the facility-specific NOX 
limit. The facility shall use the compliance procedures detailed in the 
letter and make the letter available to the public. If the 
Administrator determines it is appropriate, the conditions and 
requirements of the letter can be reviewed and changed at any point.
    (h) For purposes of paragraph (i) of this section, the 
NOX standards under this section apply at all times 
including periods of startup, shutdown, or malfunction.
    (i) Except as provided under paragraph (j) of this section, 
compliance with the emission limits under this section is determined on 
a 30-day rolling average basis.
    (j) Compliance with the emission limits under this section is 
determined on a 24-hour average basis for the initial performance test 
and on a 3-hour average basis for subsequent performance tests for any 
affected facilities that:
    (1) Combust, alone or in combination, only natural gas, distillate 
oil, or residual oil with a nitrogen content of 0.30 weight percent or 
less;
    (2) Have a combined annual capacity factor of 10 percent or less 
for natural gas, distillate oil, and residual oil with a nitrogen 
content of 0.30 weight percent or less; and
    (3) Are subject to a federally enforceable requirement limiting 
operation of the affected facility to the firing of natural gas, 
distillate oil, and/or residual oil with a nitrogen content of 0.30 
weight percent or less and limiting operation of the affected facility 
to a combined annual capacity factor of 10 percent or less for natural 
gas, distillate oil, and residual oil with a nitrogen content of 0.30 
weight percent or less.
    (k) Affected facilities that meet the criteria described in 
paragraphs (j)(1), (2), and (3) of this section, and that have a heat 
input capacity of 73 MW (250 MMBtu/hr) or less, are not subject to the 
NOX emission limits under this section.
    (l) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
commenced construction or reconstruction after July 9, 1997 shall cause 
to be discharged into the atmosphere from that affected facility any 
gases that contain NOX (expressed as NO2) in 
excess of the following limits:
    (1) If the affected facility combusts coal, oil, or natural gas, or 
a mixture of these fuels, or with any other fuels: A limit of 86 ng/JI 
(0.20 lb/MMBtu) heat input unless the affected facility has an annual 
capacity factor for coal, oil, and natural gas of 10 percent (0.10) or 
less and is subject to a federally enforceable requirement that limits 
operation of the facility to an annual capacity factor of 10 percent 
(0.10) or less for coal, oil, and natural gas; or
    (2) If the affected facility has a low heat release rate and 
combusts natural gas or distillate oil in excess of 30 percent of the 
heat input on a 30-day rolling average from the combustion of all 
fuels, a limit determined by use of the following formula: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.030

Where:

En = NOX emission limit (lb/MMBtu);
Hgo = 30-day heat input from combustion of natural gas or 
distillate oil; and
Hr = 30-day heat input from combustion of any other fuel.

    (3) After February 27, 2006, units where more than 33 percent of 
total annual output is electrical or mechanical may comply with an 
optional limit of 270 ng/J (2.1 lb/MWh) gross energy output, based on a 
30-day rolling average. Units complying with this output-based limit 
must demonstrate compliance according to the procedures of Sec.  
60.48Da(i) of subpart Da of this part, and must monitor emissions 
according to Sec.  60.49Da(c), (k), through (n) of subpart Da of this 
part.


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

    (a) The SO2 emission standards under Sec.  60.42b apply 
at all times. Facilities burning coke oven gas alone or in combination 
with any other gaseous fuels or distillate oil and complying with the 
fuel based limit under Sec.  60.42b(k)(2) are allowed to exceed the 
limit 30 operating days per calendar year for by-product plant 
maintenance.
    (b) In conducting the performance tests required under Sec.  60.8, 
the owner or operator shall use the methods and

[[Page 6359]]

procedures in appendix A (including fuel certification and sampling) of 
this part or the methods and procedures as specified in this section, 
except as provided in Sec.  60.8(b). Section 60.8(f) does not apply to 
this section. The 30-day notice required in Sec.  60.8(d) applies only 
to the initial performance test unless otherwise specified by the 
Administrator.
    (c) The owner or operator of an affected facility shall conduct 
performance tests to determine compliance with the percent of potential 
SO2 emission rate (% Ps) and the SO2 emission 
rate (Es) pursuant to Sec.  60.42b following the procedures listed 
below, except as provided under paragraph (d) and (k) of this section.
    (1) The initial performance test shall be conducted over 30 
consecutive operating days of the steam generating unit. Compliance 
with the SO2 standards shall be determined using a 30-day 
average. The first operating day included in the initial performance 
test shall be scheduled within 30 days after achieving the maximum 
production rate at which the affected facility will be operated, but 
not later than 180 days after initial startup of the facility.
    (2) If only coal, only oil, or a mixture of coal and oil is 
combusted, the following procedures are used:
    (i) The procedures in Method 19 of appendix A of this part are used 
to determine the hourly SO2 emission rate (Eho) 
and the 30-day average emission rate (Eao). The hourly 
averages used to compute the 30-day averages are obtained from the 
continuous emission monitoring system (CEMS) of Sec.  60.47b (a) or 
(b).
    (ii) The percent of potential SO2 emission rate 
(%Ps) emitted to the atmosphere is computed using the 
following formula: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.031

Where:

%Ps = Potential SO2 emission rate, percent;
%Rg = SO2 removal efficiency of the control 
device as determined by Method 19 of appendix A of this part, in 
percent; and
%Rf = SO2 removal efficiency of fuel 
pretreatment as determined by Method 19 of appendix A of this part, 
in percent.

    (3) If coal or oil is combusted with other fuels, the same 
procedures required in paragraph (c)(2) of this section are used, 
except as provided in the following:
    (i) An adjusted hourly SO2 emission rate 
(Eho\o\) is used in Equation 19-19 of Method 19 of appendix 
A of this part to compute an adjusted 30-day average emission rate 
(Eao\o\). The Eho\o\ is computed using the 
following formula: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.032

Where:

Eho\o\ = Adjusted hourly SO2 emission rate, 
ng/J (lb/MMBtu);
Eho = Hourly SO2 emission rate, ng/J (lb/
MMBtu);
Ew = SO2 concentration in fuels other than 
coal and oil combusted in the affected facility, as determined by 
the fuel sampling and analysis procedures in Method 19 of appendix A 
of this part, ng/J (lb/MMBtu). The value Ew for each fuel 
lot is used for each hourly average during the time that the lot is 
being combusted; and
Xk = Fraction of total heat input from fuel combustion 
derived from coal, oil, or coal and oil, as determined by applicable 
procedures in Method 19 of appendix A of this part.

    (ii) To compute the percent of potential SO2 emission 
rate (%Ps), an adjusted %Rg (%Rg\o\) 
is computed from the adjusted Eao\o\ from paragraph 
(b)(3)(i) of this section and an adjusted average SO2 inlet 
rate (Eai\o\) using the following formula: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.033

    To compute Eai\o\, an adjusted hourly SO2 
inlet rate (Ehi\o\) is used. The Ehi\o\ is 
computed using the following formula: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.034

Where:

Ehi\o\ = Adjusted hourly SO2 inlet rate, ng/J 
(lb/MMBtu); and
Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu).

    (4) The owner or operator of an affected facility subject to 
paragraph (b)(3) of this section does not have to measure parameters 
Ew or Xk if the owner or operator elects to 
assume that Xk = 1.0. Owners or operators of affected 
facilities who assume Xk = 1.0 shall:
    (i) Determine %Ps following the procedures in paragraph 
(c)(2) of this section; and
    (ii) Sulfur dioxide emissions (Es) are considered to be 
in compliance with SO2 emission limits under Sec.  60.42b.
    (5) The owner or operator of an affected facility that qualifies 
under the provisions of Sec.  60.42b(d) does not have to measure 
parameters Ew or Xk under paragraph (b)(3) of 
this section if the owner or operator of the affected facility elects 
to measure SO2 emission rates of the coal or oil following 
the fuel sampling and analysis procedures under Method 19 of appendix A 
of this part.
    (d) Except as provided in paragraph (j) of this section, the owner 
or operator of an affected facility that combusts only very low sulfur 
oil, has an annual capacity factor for oil of 10 percent (0.10) or 
less, and is subject to a federally enforceable requirement limiting 
operation of the affected facility to an annual capacity factor for oil 
of 10 percent (0.10) or less shall:
    (1) Conduct the initial performance test over 24 consecutive steam 
generating unit operating hours at full load;
    (2) Determine compliance with the standards after the initial 
performance test based on the arithmetic average of the hourly 
emissions data during each steam generating unit operating day if a 
CEMS is used, or based on a daily average if Method 6B of appendix A of 
this part or fuel sampling and analysis procedures under Method 19 of 
appendix A of this part are used.
    (e) The owner or operator of an affected facility subject to Sec.  
60.42b(d)(1) shall demonstrate the maximum design capacity of the steam 
generating unit by operating the facility at maximum capacity for 24 
hours. This demonstration will be made during the initial performance 
test and a subsequent demonstration may be requested at any other time. 
If the 24-hour average firing rate for the affected facility is less 
than the maximum design capacity provided by the manufacturer of the 
affected facility, the 24-hour average firing rate shall be used to 
determine the capacity utilization rate for the affected facility, 
otherwise the maximum design capacity provided by the manufacturer is 
used.
    (f) For the initial performance test required under Sec.  60.8, 
compliance with the SO2 emission limits and percent 
reduction requirements under Sec.  60.42b is based on the average 
emission rates and the average percent reduction for SO2 for 
the first 30 consecutive steam generating unit operating days, except 
as provided under paragraph (d) of this section. The initial 
performance test is the only test for which at least 30 days prior 
notice is required unless otherwise specified by the Administrator. The 
initial performance test is to be scheduled so that the first steam 
generating unit operating day of the 30 successive steam generating 
unit operating days is completed within 30 days after achieving the 
maximum production rate at which the affected facility will be 
operated, but not later than 180 days after initial startup of the 
facility. The boiler load during the 30-day period does not have to be 
the

[[Page 6360]]

maximum design load, but must be representative of future operating 
conditions and include at least one 24-hour period at full load.
    (g) After the initial performance test required under Sec.  60.8, 
compliance with the SO2 emission limits and percent 
reduction requirements under Sec.  60.42b is based on the average 
emission rates and the average percent reduction for SO2 for 
30 successive steam generating unit operating days, except as provided 
under paragraph (d). A separate performance test is completed at the 
end of each steam generating unit operating day after the initial 
performance test, and a new 30-day average emission rate and percent 
reduction for SO2 are calculated to show compliance with the 
standard.
    (h) Except as provided under paragraph (i) of this section, the 
owner or operator of an affected facility shall use all valid 
SO2 emissions data in calculating %Ps and 
Eho under paragraph (c), of this section whether or not the 
minimum emissions data requirements under Sec.  60.46b are achieved. 
All valid emissions data, including valid SO2 emission data 
collected during periods of startup, shutdown and malfunction, shall be 
used in calculating %Ps and Eho pursuant to 
paragraph (c) of this section.
    (i) During periods of malfunction or maintenance of the 
SO2 control systems when oil is combusted as provided under 
Sec.  60.42b(i), emission data are not used to calculate %Ps 
or Es under Sec.  60.42b (a), (b) or (c), however, the 
emissions data are used to determine compliance with the emission limit 
under Sec.  60.42b(i).
    (j) The owner or operator of an affected facility that combusts 
very low sulfur oil is not subject to the compliance and performance 
testing requirements of this section if the owner or operator obtains 
fuel receipts as described in Sec.  60.49b(r).
    (k) The owner or operator of an affected facility seeking to 
demonstrate compliance under Sec. Sec.  60.42b(d)(4), 60.42b(j), and 
60.42b(k)(2) shall follow the applicable procedures under Sec.  
60.49b(r).


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

    (a) The PM emission standards and opacity limits under Sec.  60.43b 
apply at all times except during periods of startup, shutdown, or 
malfunction. The NOX emission standards under Sec.  60.44b 
apply at all times.
    (b) Compliance with the PM emission standards under Sec.  60.43b 
shall be determined through performance testing as described in 
paragraph (d) of this section, except as provided in paragraph (i) of 
this section.
    (c) Compliance with the NOX emission standards under 
Sec.  60.44b shall be determined through performance testing under 
paragraph (e) or (f), or under paragraphs (g) and (h) of this section, 
as applicable.
    (d) To determine compliance with the PM emission limits and opacity 
limits under Sec.  60.43b, the owner or operator of an affected 
facility shall conduct an initial performance test as required under 
Sec.  60.8, and shall conduct subsequent performance tests as requested 
by the Administrator, using the following procedures and reference 
methods:
    (1) Method 3B of appendix A of this part is used for gas analysis 
when applying Method 5 or 17 of appendix A of this part.
    (2) Method 5, 5B, or 17 of appendix A of this part shall be used to 
measure the concentration of PM as follows:
    (i) Method 5 of appendix A of this part shall be used at affected 
facilities without wet flue gas desulfurization (FGD) systems; and
    (ii) Method 17 of appendix A of this part may be used at facilities 
with or without wet scrubber systems provided the stack gas temperature 
does not exceed a temperature of 160 [deg]C (32 [deg]F). The procedures 
of sections 2.1 and 2.3 of Method 5B of appendix A of this part may be 
used in Method 17 of appendix A of this part only if it is used after a 
wet FGD system. Do not use Method 17 of appendix A of this part after 
wet FGD systems if the effluent is saturated or laden with water 
droplets.
    (iii) Method 5B of appendix A of this part is to be used only after 
wet FGD systems.
    (3) Method 1 of appendix A of this part is used to select the 
sampling site and the number of traverse sampling points. The sampling 
time for each run is at least 120 minutes and the minimum sampling 
volume is 1.7 dscm (60 dscf) except that smaller sampling times or 
volumes may be approved by the Administrator when necessitated by 
process variables or other factors.
    (4) For Method 5 of appendix A of this part, the temperature of the 
sample gas in the probe and filter holder is monitored and is 
maintained at 16014 [deg]C (32025 [deg]F).
    (5) For determination of PM emissions, the oxygen (O2) 
or CO2 sample is obtained simultaneously with each run of 
Method 5, 5B, or 17 of appendix A of this part by traversing the duct 
at the same sampling location.
    (6) For each run using Method 5, 5B, or 17 of appendix A of this 
part, the emission rate expressed in ng/J heat input is determined 
using:
    (i) The O2 or CO2 measurements and PM 
measurements obtained under this section;
    (ii) The dry basis F factor; and
    (iii) The dry basis emission rate calculation procedure contained 
in Method 19 of appendix A of this part.
    (7) Method 9 of appendix A of this part is used for determining the 
opacity of stack emissions.
    (e) To determine compliance with the emission limits for 
NOX required under Sec.  60.44b, the owner or operator of an 
affected facility shall conduct the performance test as required under 
Sec.  60.8 using the continuous system for monitoring NOX 
under Sec.  60.48(b).
    (1) For the initial compliance test, NOX from the steam 
generating unit are monitored for 30 successive steam generating unit 
operating days and the 30-day average emission rate is used to 
determine compliance with the NOX emission standards under 
Sec.  60.44b. The 30-day average emission rate is calculated as the 
average of all hourly emissions data recorded by the monitoring system 
during the 30-day test period.
    (2) Following the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, the owner or operator of an affected facility which 
combusts coal or which combusts residual oil having a nitrogen content 
greater than 0.30 weight percent shall determine compliance with the 
NOX emission standards under Sec.  60.44b on a continuous 
basis through the use of a 30-day rolling average emission rate. A new 
30-day rolling average emission rate is calculated each steam 
generating unit operating day as the average of all of the hourly 
NOX emission data for the preceding 30 steam generating unit 
operating days.
    (3) Following the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, the owner or operator of an affected facility that 
has a heat input capacity greater than 73 MW (250 MMBtu/hr) and that 
combusts natural gas, distillate oil, or residual oil having a nitrogen 
content of 0.30 weight percent or less shall determine compliance with 
the NOX standards under Sec.  60.44b on a continuous basis 
through the use of a 30-day rolling average emission rate. A new 30-day 
rolling average emission rate is calculated each steam generating unit 
operating day as the average of all of the hourly NOX 
emission data for the preceding 30 steam generating unit operating 
days.

[[Page 6361]]

    (4) Following the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, the owner or operator of an affected facility that has a 
heat input capacity of 73 MW (250 MMBtu/hr) or less and that combusts 
natural gas, distillate oil, or residual oil having a nitrogen content 
of 0.30 weight percent or less shall upon request determine compliance 
with the NOX standards under Sec.  60.44b through the use of 
a 30-day performance test. During periods when performance tests are 
not requested, NOX emissions data collected pursuant to 
Sec.  60.48b(g)(1) or Sec.  60.48b(g)(2) are used to calculate a 30-day 
rolling average emission rate on a daily basis and used to prepare 
excess emission reports, but will not be used to determine compliance 
with the NOX emission standards. A new 30-day rolling 
average emission rate is calculated each steam generating unit 
operating day as the average of all of the hourly NOX 
emission data for the preceding 30 steam generating unit operating 
days.
    (5) If the owner or operator of an affected facility that combusts 
residual oil does not sample and analyze the residual oil for nitrogen 
content, as specified in Sec.  60.49b(e), the requirements of Sec.  
60.48b(g)(1) apply and the provisions of Sec.  60.48b(g)(2) are 
inapplicable.
    (f) To determine compliance with the emissions limits for 
NOX required by Sec.  60.44b(a)(4) or Sec.  60.44b(l) for 
duct burners used in combined cycle systems, either of the procedures 
described in paragraph (f)(1) or (2) of this section may be used:
    (1) The owner or operator of an affected facility shall conduct the 
performance test required under Sec.  60.8 as follows:
    (i) The emissions rate (E) of NOX shall be computed 
using Equation 1 in this section: 
[GRAPHIC] [TIFF OMITTED] TP09FE07.035

Where:

E = Emissions rate of NOX from the duct burner, ng/J (lb/
MMBtu) heat input;
Esg = Combined effluent emissions rate, in ng/J (lb/
MMBtu) heat input using appropriate F factor as described in Method 
19 of appendix A of this part;
Hg = Heat input rate to the combustion turbine, in J/hr 
(MMBtu/hr);
Hb = Heat input rate to the duct burner, in J/hr (MMBtu/
hr); and
Eg = Emissions rate from the combustion turbine, in ng/J 
(lb/MMBtu) heat input calculated using appropriate F factor as 
described in Method 19 of appendix A of this part.

    (ii) Method 7E of appendix A of this part shall be used to 
determine the NOX concentrations. Method 3A or 3B of 
appendix A of this part shall be used to determine O2 
concentration.
    (iii) The owner or operator shall identify and demonstrate to the 
Administrator's satisfaction suitable methods to determine the average 
hourly heat input rate to the combustion turbine and the average hourly 
heat input rate to the affected duct burner.
    (iv) Compliance with the emissions limits under Sec.  60.44b (a)(4) 
or Sec.  60.44b(l) is determined by the three-run average (nominal 1-
hour runs) for the initial and subsequent performance tests; or
    (2) The owner or operator of an affected facility may elect to 
determine compliance on a 30-day rolling average basis by using the 
CEMS specified under Sec.  60.48b for measuring NOX and 
O2 and meet the requirements of Sec.  60.48b. The sampling 
site shall be located at the outlet from the steam generating unit. The 
NOX emissions rate at the outlet from the steam generating 
unit shall constitute the NOX emissions rate from the duct 
burner of the combined cycle system.
    (g) The owner or operator of an affected facility described in 
Sec.  60.44b(j) or Sec.  60.44b(k) shall demonstrate the maximum heat 
input capacity of the steam generating unit by operating the facility 
at maximum capacity for 24 hours. The owner or operator of an affected 
facility shall determine the maximum heat input capacity using the heat 
loss method described in sections 5 and 7.3 of the ASME Power Test 
Codes 4.1 (incorporated by reference, see Sec.  60.17). This 
demonstration of maximum heat input capacity shall be made during the 
initial performance test for affected facilities that meet the criteria 
of Sec.  60.44b(j). It shall be made within 60 days after achieving the 
maximum production rate at which the affected facility will be 
operated, but not later than 180 days after initial start-up of each 
facility, for affected facilities meeting the criteria of Sec.  
60.44b(k). Subsequent demonstrations may be required by the 
Administrator at any other time. If this demonstration indicates that 
the maximum heat input capacity of the affected facility is less than 
that stated by the manufacturer of the affected facility, the maximum 
heat input capacity determined during this demonstration shall be used 
to determine the capacity utilization rate for the affected facility. 
Otherwise, the maximum heat input capacity provided by the manufacturer 
is used.
    (h) The owner or operator of an affected facility described in 
Sec.  60.44b(j) that has a heat input capacity greater than 73 MW (250 
MMBtu/hr) shall:
    (1) Conduct an initial performance test as required under Sec.  
60.8 over a minimum of 24 consecutive steam generating unit operating 
hours at maximum heat input capacity to demonstrate compliance with the 
NOX emission standards under Sec.  60.44b using Method 7, 
7A, 7E of appendix A of this part, or other approved reference methods; 
and
    (2) Conduct subsequent performance tests once per calendar year or 
every 400 hours of operation (whichever comes first) to demonstrate 
compliance with the NOX emission standards under Sec.  
60.44b over a minimum of 3 consecutive steam generating unit operating 
hours at maximum heat input capacity using Method 7, 7A, 7E of appendix 
A of this part, or other approved reference methods.
    (i) The owner or operator of an affected facility seeking to 
demonstrate compliance under paragraph Sec.  60.43b(h)(5) shall follow 
the applicable procedures under Sec.  60.49b(r).
    (j) In place of PM testing with EPA Reference Method 5, 5B, or 17 
of appendix A of this part, an owner or operator may elect to install, 
calibrate, maintain, and operate a CEMS for monitoring PM emissions 
discharged to the atmosphere and record the output of the system. The 
owner or operator of an affected facility who elects to continuously 
monitor PM emissions instead of conducting performance testing using 
EPA Method 5, 5B, or 17 of appendix A of this part shall comply with 
the requirements specified in paragraphs (j)(1) through (j)(13) of this 
section.
    (1) Notify the Administrator one month before starting use of the 
system.
    (2) Notify the Administrator one month before stopping use of the 
system.
    (3) The monitor shall be installed, evaluated, and operated in 
accordance with Sec.  60.13 of subpart A of this part.
    (4) The initial performance evaluation shall be completed no later 
than 180 days after the date of initial startup of the affected 
facility, as specified under Sec.  60.8 of subpart A of this part or 
within 180 days of notification to the Administrator of use of the CEMS 
if the owner or operator was previously determining compliance by 
Method 5, 5B, or 17 of appendix A of this part performance tests, 
whichever is later.
    (5) The owner or operator of an affected facility shall conduct an 
initial performance test for PM emissions as required under Sec.  60.8 
of subpart A of this part. Compliance with the PM emission limit shall 
be determined by

[[Page 6362]]

using the CEMS specified in paragraph (j) of this section to measure PM 
and calculating a 24-hour block arithmetic average emission 
concentration using EPA Reference Method 19 of appendix A of this part, 
section 4.1.
    (6) Compliance with the PM emission limit shall be determined based 
on the 24-hour daily (block) average of the hourly arithmetic average 
emission concentrations using CEMS outlet data.
    (7) At a minimum, valid CEMS hourly averages shall be obtained as 
specified in paragraphs (j)(7)(i) of this section for 75 percent of the 
total operating hours per 30-day rolling average.
    (i) At least two data points per hour shall be used to calculate 
each 1-hour arithmetic average.
    (8) The 1-hour arithmetic averages required under paragraph (j)(7) 
of this section shall be expressed in ng/J or lb/MMBtu heat input and 
shall be used to calculate the boiler operating day daily arithmetic 
average emission concentrations. The 1-hour arithmetic averages shall 
be calculated using the data points required under Sec.  60.13(e)(2) of 
subpart A of this part.
    (9) All valid CEMS data shall be used in calculating average 
emission concentrations even if the minimum CEMS data requirements of 
paragraph (j)(7) of this section are not met.
    (10) The CEMS shall be operated according to Performance 
Specification 11 in appendix B of this part.
    (11) During the correlation testing runs of the CEMS required by 
Performance Specification 11 in appendix B of this part, PM and 
O2 (or CO2) data shall be collected concurrently 
(or within a 30-to 60-minute period) by both the continuous emission 
monitors and the test methods specified in paragraph (j)(7)(i) of this 
section.
    (i) For PM, EPA Reference Method 5, 5B, or 17 of appendix A of this 
part shall be used.
    (ii) For O2 (or CO2), EPA reference Method 3, 
3A, or 3B of appendix A of this part, as applicable shall be used.
    (12) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with procedure 2 in appendix F 
of this part. Relative Response Audits must be performed annually and 
Response Correlation Audits must be performed every 3 years.
    (13) When PM emissions data are not obtained because of CEMS 
breakdowns, repairs, calibration checks, and zero and span adjustments, 
emissions data shall be obtained by using other monitoring systems as 
approved by the Administrator or EPA Reference Method 19 of appendix A 
of this part to provide, as necessary, valid emissions data for a 
minimum of 75 percent of total operating hours per 30-day rolling 
average.


Sec.  60.47b  Emission monitoring for sulfur dioxide.

    (a) Except as provided in paragraphs (b) and (g) of this section, 
the owner or operator of an affected facility subject to the 
SO2 standards under Sec.  60.42b shall install, calibrate, 
maintain, and operate CEMS for measuring SO2 concentrations 
and either O2 or CO2 concentrations and shall 
record the output of the systems. For units complying with the percent 
reduction standard, the SO2 and either O2 or 
CO2 concentrations shall both be monitored at the inlet and 
outlet of the SO2 control device.
    (b) As an alternative to operating CEMS as required under paragraph 
(a) of this section, an owner or operator may elect to determine the 
average SO2 emissions and percent reduction by:
    (1) Collecting coal or oil samples in an as-fired condition at the 
inlet to the steam generating unit and analyzing them for sulfur and 
heat content according to Method 19 of appendix A of this part. Method 
19 of appendix A of this part provides procedures for converting these 
measurements into the format to be used in calculating the average 
SO2 input rate, or
    (2) Measuring SO2 according to Method 6B of appendix A 
of this part at the inlet or outlet to the SO2 control 
system. An initial stratification test is required to verify the 
adequacy of the Method 6B of appendix A of this part sampling location. 
The stratification test shall consist of three paired runs of a 
suitable SO2 and CO2 measurement train operated 
at the candidate location and a second similar train operated according 
to the procedures in section 3.2 and the applicable procedures in 
section 7 of Performance Specification 2. Method 6B of appendix A of 
this part, Method 6A of appendix A of this part, or a combination of 
Methods 6 and 3 or 3B of appendix A of this part or Methods 6C and 3A 
of appendix A of this part are suitable measurement techniques. If 
Method 6B of appendix A of this part is used for the second train, 
sampling time and timer operation may be adjusted for the 
stratification test as long as an adequate sample volume is collected; 
however, both sampling trains are to be operated similarly. For the 
location to be adequate for Method 6B of appendix A of this part 24-
hour tests, the mean of the absolute difference between the three 
paired runs must be less than 10 percent.
    (3) A daily SO2 emission rate, ED, shall be determined 
using the procedure described in Method 6A of appendix A of this part, 
section 7.6.2 (Equation 6A-8) and stated in ng/J (lb/MMBtu) heat input.
    (4) The mean 30-day emission rate is calculated using the daily 
measured values in ng/J (lb/MMBtu) for 30 successive steam generating 
unit operating days using equation 19-20 of Method 19 of appendix A of 
this part.
    (c) The owner or operator of an affected facility shall obtain 
emission data for at least 75 percent of the operating hours in at 
least 22 out of 30 successive boiler operating days. If this minimum 
data requirement is not met with a single monitoring system, the owner 
or operator of the affected facility shall supplement the emission data 
with data collected with other monitoring systems as approved by the 
Administrator or the reference methods and procedures as described in 
paragraph (b) of this section.
    (d) The 1-hour average SO2 emission rates measured by 
the CEMS required by paragraph (a) of this section and required under 
Sec.  60.13(h) is expressed in ng/J or lb/MMBtu heat input and is used 
to calculate the average emission rates under Sec.  60.42(b). Each 1-
hour average SO2 emission rate must be based on 30 or more 
minutes of steam generating unit operation. The hourly averages shall 
be calculated according to Sec.  60.13(h)(2). Hourly SO2 
emission rates are not calculated if the affected facility is operated 
less than 30 minutes in a given clock hour and are not counted toward 
determination of a steam generating unit operating day.
    (e) The procedures under Sec.  60.13 shall be followed for 
installation, evaluation, and operation of the CEMS.
    (1) All CEMS shall be operated in accordance with the applicable 
procedures under Performance Specifications 1, 2, and 3 of appendix B 
of this part.
    (2) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with Procedure 1 of appendix F 
of this part.
    (3) For affected facilities combusting coal or oil, alone or in 
combination with other fuels, the span value of the SO2 CEMS 
at the inlet to the SO2 control device is 125 percent of the 
maximum estimated hourly potential SO2 emissions of the fuel 
combusted, and the span value of the CEMS at the outlet to the 
SO2 control device is 50 percent of the maximum estimated 
hourly potential SO2 emissions of the fuel combusted.
    (f) The owner or operator of an affected facility that combusts 
very low sulfur oil or is demonstrating compliance under Sec.  
60.45b(k) is not

[[Page 6363]]

subject to the emission monitoring requirements under paragraph (a) of 
this section if the owner or operator maintains fuel records as 
described in Sec.  60.49b(r).


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

    (a) Except as provided in paragraph (j) of this section, the owner 
or operator of an affected facility subject to the opacity standard 
under Sec.  60.43b shall install, calibrate, maintain, and operate a 
CEMS for measuring the opacity of emissions discharged to the 
atmosphere and record the output of the system.
    (b) Except as provided under paragraphs (g), (h), and (i) of this 
section, the owner or operator of an affected facility subject to a 
NOX standard under Sec.  60.44b shall comply with either 
paragraphs (b)(1) or (b)(2) of this section.
    (1) Install, calibrate, maintain, and operate a CEMS, and record 
the output of the system, for measuring NOX emissions 
discharged to the atmosphere; or
    (2) If the owner or operator has installed a NOX 
emission rate CEMS to meet the requirements of part 75 of this chapter 
and is continuing to meet the ongoing requirements of part 75 of this 
chapter, that CEMS may be used to meet the requirements of this 
section, except that the owner or operator shall also meet the 
requirements of Sec.  60.49b. Data reported to meet the requirements of 
Sec.  60.49b shall not include data substituted using the missing data 
procedures in subpart D of part 75 of this chapter, nor shall the data 
have been bias adjusted according to the procedures of part 75 of this 
chapter.
    (c) The CEMS required under paragraph (b) of this section shall be 
operated and data recorded during all periods of operation of the 
affected facility except for CEMS breakdowns and repairs. Data is 
recorded during calibration checks, and zero and span adjustments.
    (d) The 1-hour average NOX emission rates measured by 
the continuous NOX monitor required by paragraph (b) of this 
section and required under Sec.  60.13(h) shall be expressed in ng/J or 
lb/MMBtu heat input and shall be used to calculate the average emission 
rates under Sec.  60.44b. The 1-hour averages shall be calculated using 
the data points required under Sec.  60.13(h)(2).
    (e) The procedures under Sec.  60.13 shall be followed for 
installation, evaluation, and operation of the continuous monitoring 
systems.
    (1) For affected facilities combusting coal, wood or municipal-type 
solid waste, the span value for a continuous monitoring system for 
measuring opacity shall be between 60 and 80 percent.
    (2) For affected facilities combusting coal, oil, or natural gas, 
the span value for NOX is determined as follows:

------------------------------------------------------------------------
                 Fuel                      Span values for NOX  (ppm)
------------------------------------------------------------------------
Natural gas..........................  500
Oil..................................  500
Coal.................................  1,000
Mixtures.............................  500(x + y) + 1,000z
------------------------------------------------------------------------

Where:

x = Fraction of total heat input derived from natural gas;
y = Fraction of total heat input derived from oil; and
z = Fraction of total heat input derived from coal.

    (3) All span values computed under paragraph (e)(2) of this section 
for combusting mixtures of regulated fuels are rounded to the nearest 
500 ppm.
    (f) When NOX emission data are not obtained because of 
CEMS breakdowns, repairs, calibration checks and zero and span 
adjustments, emission data will be obtained by using standby monitoring 
systems, Method 7 of appendix A of this part, Method 7A of appendix A 
of this part, or other approved reference methods to provide emission 
data for a minimum of 75 percent of the operating hours in each steam 
generating unit operating day, in at least 22 out of 30 successive 
steam generating unit operating days.
    (g) The owner or operator of an affected facility that has a heat 
input capacity of 73 MW (250 MMBtu/hr) or less, and that has an annual 
capacity factor for residual oil having a nitrogen content of 0.30 
weight percent or less, natural gas, distillate oil, or any mixture of 
these fuels, greater than 10 percent (0.10) shall:
    (1) Comply with the provisions of paragraphs (b), (c), (d), (e)(2), 
(e)(3), and (f) of this section; or
    (2) Monitor steam generating unit operating conditions and predict 
NOX emission rates as specified in a plan submitted pursuant 
to Sec.  60.49b(c).
    (h) The owner or operator of a duct burner, as described in Sec.  
60.41b, that is subject to the NOX standards of Sec.  
60.44b(a)(4) or Sec.  60.44b(l) is not required to install or operate a 
continuous emissions monitoring system to measure NOX 
emissions.
    (i) The owner or operator of an affected facility described in 
Sec.  60.44b(j) or Sec.  60.44b(k) is not required to install or 
operate a CEMS for measuring NOX emissions.
    (j) Units are not required to operate COMS for measuring opacity 
if:
    (1) The affected facility uses a PM CEMS to monitor PM emissions; 
or
    (2) The affected facility burns only liquid (excluding residual 
oil) or gaseous fuels with potential SO2 emissions rates of 
26 ng/J (0.060 lb/MMBtu) or less and does not use a post combustion 
technology to reduce SO2 or PM emissions. The owner or 
operator must maintain fuel records of the sulfur content of the fuels 
burned, as described under Sec.  60.49b(r); or
    (3) The affected facility burns coke oven gas alone or in 
combination with fuels meeting the criteria in paragraph (j)(2) of this 
section and does not use a post combustion technology to reduce 
SO2 or PM emissions.
    (k) Owners or operators complying with the PM emission limit by 
using a PM CEMS monitor instead of monitoring opacity must calibrate, 
maintain, and operate a CEMS, and record the output of the system, for 
PM emissions discharged to the atmosphere as specified in Sec.  
60.46b(j). The CEMS specified in paragraph Sec.  60.46b(j) shall be 
operated and data recorded during all periods of operation of the 
affected facility except for CEMS breakdowns and repairs. Data is 
recorded during calibration checks, and zero and span adjustments.


Sec.  60.49b  Reporting and recordkeeping requirements.

    (a) The owner or operator of each affected facility shall submit 
notification of the date of initial startup, as provided by Sec.  60.7. 
This notification shall include:
    (1) The design heat input capacity of the affected facility and 
identification of the fuels to be combusted in the affected facility;
    (2) If applicable, a copy of any federally enforceable requirement 
that limits the annual capacity factor for any fuel or mixture of fuels 
under Sec. Sec.  60.42b(d)(1), 60.43b(a)(2), (a)(3)(iii), (c)(2)(ii), 
(d)(2)(iii), 60.44b(c), (d), (e), (i), (j), (k), 60.45b(d), (g), 
60.46b(h), or 60.48b(i);
    (3) The annual capacity factor at which the owner or operator 
anticipates operating the facility based on all fuels fired and based 
on each individual fuel fired; and
    (4) Notification that an emerging technology will be used for 
controlling emissions of SO2. The Administrator will examine 
the description of the emerging technology and will determine whether 
the technology qualifies as an emerging technology. In making this 
determination, the Administrator may require the owner or operator of 
the

[[Page 6364]]

affected facility to submit additional information concerning the 
control device. The affected facility is subject to the provisions of 
Sec.  60.42b(a) unless and until this determination is made by the 
Administrator.
    (b) The owner or operator of each affected facility subject to the 
SO2, PM, and/or NOX emission limits under 
Sec. Sec.  60.42b, 60.43b, and 60.44b shall submit to the Administrator 
the performance test data from the initial performance test and the 
performance evaluation of the CEMS using the applicable performance 
specifications in appendix B of this part. The owner or operator of 
each affected facility described in Sec.  60.44b(j) or Sec.  60.44b(k) 
shall submit to the Administrator the maximum heat input capacity data 
from the demonstration of the maximum heat input capacity of the 
affected facility.
    (c) The owner or operator of each affected facility subject to the 
NOX standard of Sec.  60.44b who seeks to demonstrate 
compliance with those standards through the monitoring of steam 
generating unit operating conditions under the provisions of Sec.  
60.48b(g)(2) shall submit to the Administrator for approval a plan that 
identifies the operating conditions to be monitored under Sec.  
60.48b(g)(2) and the records to be maintained under Sec.  60.49b(j). 
This plan shall be submitted to the Administrator for approval within 
360 days of the initial startup of the affected facility. If the plan 
is approved, the owner or operator shall maintain records of predicted 
nitrogen oxide emission rates and the monitored operating conditions, 
including steam generating unit load, identified in the plan. The plan 
shall:
    (1) Identify the specific operating conditions to be monitored and 
the relationship between these operating conditions and NOX 
emission rates (i.e., ng/J or lbs/MMBtu heat input). Steam generating 
unit operating conditions include, but are not limited to, the degree 
of staged combustion (i.e., the ratio of primary air to secondary and/
or tertiary air) and the level of excess air (i.e., flue gas 
O2 level);
    (2) Include the data and information that the owner or operator 
used to identify the relationship between NOX emission rates 
and these operating conditions; and
    (3) Identify how these operating conditions, including steam 
generating unit load, will be monitored under Sec.  60.48b(g) on an 
hourly basis by the owner or operator during the period of operation of 
the affected facility; the quality assurance procedures or practices 
that will be employed to ensure that the data generated by monitoring 
these operating conditions will be representative and accurate; and the 
type and format of the records of these operating conditions, including 
steam generating unit load, that will be maintained by the owner or 
operator under Sec.  60.49b(j).
    (d) The owner or operator of an affected facility shall record and 
maintain records of the amounts of each fuel combusted during each day 
and calculate the annual capacity factor individually for coal, 
distillate oil, residual oil, natural gas, wood, and municipal-type 
solid waste for the reporting period. The annual capacity factor is 
determined on a 12-month rolling average basis with a new annual 
capacity factor calculated at the end of each calendar month.
    (e) For an affected facility that combusts residual oil and meets 
the criteria under Sec. Sec.  60.46b(e)(4), 60.44b (j), or (k), the 
owner or operator shall maintain records of the nitrogen content of the 
residual oil combusted in the affected facility and calculate the 
average fuel nitrogen content for the reporting period. The nitrogen 
content shall be determined using ASTM Method D4629 (incorporated by 
reference, see Sec.  60.17), or fuel suppliers. If residual oil blends 
are being combusted, fuel nitrogen specifications may be prorated based 
on the ratio of residual oils of different nitrogen content in the fuel 
blend.
    (f) For facilities subject to the opacity standard under Sec.  
60.43b, the owner or operator shall maintain records of opacity.
    (g) Except as provided under paragraph (p) of this section, the 
owner or operator of an affected facility subject to the NOX 
standards under Sec.  60.44b shall maintain records of the following 
information for each steam generating unit operating day:
    (1) Calendar date;
    (2) The average hourly NOX emission rates (expressed as 
NO2) (ng/J or lb/MMBtu heat input) measured or predicted;
    (3) The 30-day average NOX emission rates (ng/J or lb/
MMBtu heat input) calculated at the end of each steam generating unit 
operating day from the measured or predicted hourly nitrogen oxide 
emission rates for the preceding 30 steam generating unit operating 
days;
    (4) Identification of the steam generating unit operating days when 
the calculated 30-day average NOX emission rates are in 
excess of the NOX emissions standards under Sec.  60.44b, 
with the reasons for such excess emissions as well as a description of 
corrective actions taken;
    (5) Identification of the steam generating unit operating days for 
which pollutant data have not been obtained, including reasons for not 
obtaining sufficient data and a description of corrective actions 
taken;
    (6) Identification of the times when emission data have been 
excluded from the calculation of average emission rates and the reasons 
for excluding data;
    (7) Identification of ``F'' factor used for calculations, method of 
determination, and type of fuel combusted;
    (8) Identification of the times when the pollutant concentration 
exceeded full span of the CEMS;
    (9) Description of any modifications to the CEMS that could affect 
the ability of the CEMS to comply with Performance Specification 2 or 
3; and
    (10) Results of daily CEMS drift tests and quarterly accuracy 
assessments as required under appendix F, Procedure 1 of this part.
    (h) The owner or operator of any affected facility in any category 
listed in paragraphs (h) (1) or (2) of this section is required to 
submit excess emission reports for any excess emissions that occurred 
during the reporting period.
    (1) Any affected facility subject to the opacity standards under 
Sec.  60.43b(e) or to the operating parameter monitoring requirements 
under Sec.  60.13(i)(1).
    (2) Any affected facility that is subject to the NOX 
standard of Sec.  60.44b, and that:
    (i) Combusts natural gas, distillate oil, or residual oil with a 
nitrogen content of 0.3 weight percent or less; or
    (ii) Has a heat input capacity of 73 MW (250 MMBtu/hr) or less and 
is required to monitor NOX emissions on a continuous basis 
under Sec.  60.48b(g)(1) or steam generating unit operating conditions 
under Sec.  60.48b(g)(2).
    (3) For the purpose of Sec.  60.43b, excess emissions are defined 
as all 6-minute periods during which the average opacity exceeds the 
opacity standards under Sec.  60.43b(f).
    (4) For purposes of Sec.  60.48b(g)(1), excess emissions are 
defined as any calculated 30-day rolling average NOX 
emission rate, as determined under Sec.  60.46b(e), that exceeds the 
applicable emission limits in Sec.  60.44b.
    (i) The owner or operator of any affected facility subject to the 
continuous monitoring requirements for NOX under Sec.  
60.48(b) shall submit reports containing the information recorded under 
paragraph (g) of this section.
    (j) The owner or operator of any affected facility subject to the 
SO2 standards under Sec.  60.42b shall submit reports.

[[Page 6365]]

    (k) For each affected facility subject to the compliance and 
performance testing requirements of Sec.  60.45b and the reporting 
requirement in paragraph (j) of this section, the following information 
shall be reported to the Administrator:
    (1) Calendar dates covered in the reporting period;
    (2) Each 30-day average SO2 emission rate (ng/J or 1b/
MMBtu heat input) measured during the reporting period, ending with the 
last 30-day period; reasons for noncompliance with the emission 
standards; and a description of corrective actions taken;
    (3) Each 30-day average percent reduction in SO2 
emissions calculated during the reporting period, ending with the last 
30-day period; reasons for noncompliance with the emission standards; 
and a description of corrective actions taken;
    (4) Identification of the steam generating unit operating days that 
coal or oil was combusted and for which SO2 or diluent 
(O2 or CO2) data have not been obtained by an 
approved method for at least 75 percent of the operating hours in the 
steam generating unit operating day; justification for not obtaining 
sufficient data; and description of corrective action taken;
    (5) Identification of the times when emissions data have been 
excluded from the calculation of average emission rates; justification 
for excluding data; and description of corrective action taken if data 
have been excluded for periods other than those during which coal or 
oil were not combusted in the steam generating unit;
    (6) Identification of ``F'' factor used for calculations, method of 
determination, and type of fuel combusted;
    (7) Identification of times when hourly averages have been obtained 
based on manual sampling methods;
    (8) Identification of the times when the pollutant concentration 
exceeded full span of the CEMS;
    (9) Description of any modifications to the CEMS that could affect 
the ability of the CEMS to comply with Performance Specification 2 or 
3;
    (10) Results of daily CEMS drift tests and quarterly accuracy 
assessments as required under appendix F, Procedure 1 of this part; and
    (11) The annual capacity factor of each fired as provided under 
paragraph (d) of this section.
    (l) For each affected facility subject to the compliance and 
performance testing requirements of Sec.  60.45b(d) and the reporting 
requirements of paragraph (j) of this section, the following 
information shall be reported to the Administrator:
    (1) Calendar dates when the facility was in operation during the 
reporting period;
    (2) The 24-hour average SO2 emission rate measured for 
each steam generating unit operating day during the reporting period 
that coal or oil was combusted, ending in the last 24-hour period in 
the quarter; reasons for noncompliance with the emission standards; and 
a description of corrective actions taken;
    (3) Identification of the steam generating unit operating days that 
coal or oil was combusted for which SO2 or diluent 
(O2 or CO2) data have not been obtained by an 
approved method for at least 75 percent of the operating hours; 
justification for not obtaining sufficient data; and description of 
corrective action taken;
    (4) Identification of the times when emissions data have been 
excluded from the calculation of average emission rates; justification 
for excluding data; and description of corrective action taken if data 
have been excluded for periods other than those during which coal or 
oil were not combusted in the steam generating unit;
    (5) Identification of ``F'' factor used for calculations, method of 
determination, and type of fuel combusted;
    (6) Identification of times when hourly averages have been obtained 
based on manual sampling methods;
    (7) Identification of the times when the pollutant concentration 
exceeded full span of the CEMS;
    (8) Description of any modifications to the CEMS that could affect 
the ability of the CEMS to comply with Performance Specification 2 or 
3; and
    (9) Results of daily CEMS drift tests and quarterly accuracy 
assessments as required under appendix F, Procedure 1 of this part.
    (m) For each affected facility subject to the SO2 
standards under Sec.  60.42(b) for which the minimum amount of data 
required under Sec.  60.47b(f) were not obtained during the reporting 
period, the following information is reported to the Administrator in 
addition to that required under paragraph (k) of this section:
    (1) The number of hourly averages available for outlet emission 
rates and inlet emission rates;
    (2) The standard deviation of hourly averages for outlet emission 
rates and inlet emission rates, as determined in Method 19 of appendix 
A of this part, section 7;
    (3) The lower confidence limit for the mean outlet emission rate 
and the upper confidence limit for the mean inlet emission rate, as 
calculated in Method 19 of appendix A of this part, section 7; and
    (4) The ratio of the lower confidence limit for the mean outlet 
emission rate and the allowable emission rate, as determined in Method 
19 of appendix A of this part, section 7.
    (n) If a percent removal efficiency by fuel pretreatment (i.e., 
%Rf) is used to determine the overall percent reduction 
(i.e., %Ro) under Sec.  60.45b, the owner or operator of the 
affected facility shall submit a signed statement with the report.
    (1) Indicating what removal efficiency by fuel pretreatment (i.e., 
%Rf) was credited during the reporting period;
    (2) Listing the quantity, heat content, and date each pre-treated 
fuel shipment was received during the reporting period, the name and 
location of the fuel pretreatment facility; and the total quantity and 
total heat content of all fuels received at the affected facility 
during the reporting period;
    (3) Documenting the transport of the fuel from the fuel 
pretreatment facility to the steam generating unit; and
    (4) Including a signed statement from the owner or operator of the 
fuel pretreatment facility certifying that the percent removal 
efficiency achieved by fuel pretreatment was determined in accordance 
with the provisions of Method 19 of appendix A of this part and listing 
the heat content and sulfur content of each fuel before and after fuel 
pretreatment.
    (o) All records required under this section shall be maintained by 
the owner or operator of the affected facility for a period of 2 years 
following the date of such record.
    (p) The owner or operator of an affected facility described in 
Sec.  60.44b(j) or (k) shall maintain records of the following 
information for each steam generating unit operating day:
    (1) Calendar date;
    (2) The number of hours of operation; and
    (3) A record of the hourly steam load.
    (q) The owner or operator of an affected facility described in 
Sec.  60.44b(j) or Sec.  60.44b(k) shall submit to the Administrator a 
report containing:
    (1) The annual capacity factor over the previous 12 months;
    (2) The average fuel nitrogen content during the reporting period, 
if residual oil was fired; and
    (3) If the affected facility meets the criteria described in Sec.  
60.44b(j), the results of any NOX emission tests required 
during the reporting period, the hours of operation during the 
reporting period, and the hours of operation since the last 
NOX emission test.

[[Page 6366]]

    (r) The owner or operator of an affected facility who elects to use 
the fuel based compliance alternatives in Sec.  60.42b or Sec.  60.43b 
shall either:
    (1) The owner or operator of an affected facility who elects to 
demonstrate that the affected facility combusts only very low sulfur 
oil under Sec.  60.42b(j)(2) or Sec.  60.42b(k)(2) shall obtain and 
maintain at the affected facility fuel receipts from the fuel supplier 
that certify that the oil meets the definition of distillate oil as 
defined in Sec.  60.41b and the applicable sulfur limit. For the 
purposes of this section, the distillate oil need not meet the fuel 
nitrogen content specification in the definition of distillate oil. 
Reports shall be submitted to the Administrator certifying that only 
very low sulfur oil meeting this definition and/or pipeline quality 
natural gas was combusted in the affected facility during the reporting 
period; or
    (2) The owner or operator of an affected facility who elects to 
demonstrate compliance based on fuel analysis in Sec.  60.42b or Sec.  
60.43b shall develop and submit a site-specific fuel analysis plan to 
the Administrator for review and approval no later than 60 days before 
the date you intend to demonstrate compliance. Each fuel analysis plan 
shall include a minimum initial requirement of weekly testing and each 
analysis report shall contain, at a minimum, the following information:
    (i) The potential sulfur emissions rate of the representative fuel 
mixture in ng/J heat input;
    (ii) The method used to determine the potential sulfur emissions 
rate of each constituent of the mixture. For distillate oil and natural 
gas a fuel receipt or tariff sheet is acceptable;
    (iii) The ratio of different fuels in the mixture; and
    (iv) The owner or operator can petition the Administrator to 
approve monthly or quarterly sampling in place of weekly sampling.
    (s) Facility specific NOX standard for Cytec Industries 
Fortier Plant's C.AOG incinerator located in Westwego, Louisiana:
    (1) Definitions.
    Oxidation zone is defined as the portion of the C.AOG incinerator 
that extends from the inlet of the oxidizing zone combustion air to the 
outlet gas stack.
    Reducing zone is defined as the portion of the C.AOG incinerator 
that extends from the burner section to the inlet of the oxidizing zone 
combustion air.
    Total inlet air is defined as the total amount of air introduced 
into the C.AOG incinerator for combustion of natural gas and chemical 
by-product waste and is equal to the sum of the air flow into the 
reducing zone and the air flow into the oxidation zone.
    (2) Standard for nitrogen oxides. (i) When fossil fuel alone is 
combusted, the NOX emission limit for fossil fuel in Sec.  
60.44b(a) applies.
    (ii) When natural gas and chemical by-product waste are 
simultaneously combusted, the NOX emission limit is 289 ng/J 
(0.67 lb/MMBtu) and a maximum of 81 percent of the total inlet air 
provided for combustion shall be provided to the reducing zone of the 
C.AOG incinerator.
    (3) Emission monitoring. (i) The percent of total inlet air 
provided to the reducing zone shall be determined at least every 15 
minutes by measuring the air flow of all the air entering the reducing 
zone and the air flow of all the air entering the oxidation zone, and 
compliance with the percentage of total inlet air that is provided to 
the reducing zone shall be determined on a 3-hour average basis.
    (ii) The NOX emission limit shall be determined by the 
compliance and performance test methods and procedures for 
NOX in Sec.  60.46b(i).
    (iii) The monitoring of the NOX emission limit shall be 
performed in accordance with Sec.  60.48b.
    (4) Reporting and recordkeeping requirements. (i) The owner or 
operator of the C.AOG incinerator shall submit a report on any 
excursions from the limits required by paragraph (a)(2) of this section 
to the Administrator with the quarterly report required by paragraph 
(i) of this section.
    (ii) The owner or operator of the C.AOG incinerator shall keep 
records of the monitoring required by paragraph (a)(3) of this section 
for a period of 2 years following the date of such record.
    (iii) The owner of operator of the C.AOG incinerator shall perform 
all the applicable reporting and recordkeeping requirements of this 
section.
    (t) Facility-specific NOX standard for Rohm and Haas 
Kentucky Incorporated's Boiler No. 100 located in Louisville, Kentucky:
    (1) Definitions.
    Air ratio control damper is defined as the part of the low 
NOX burner that is adjusted to control the split of total 
combustion air delivered to the reducing and oxidation portions of the 
combustion flame.
    Flue gas recirculation line is defined as the part of Boiler No. 
100 that recirculates a portion of the boiler flue gas back into the 
combustion air.
    (2) Standard for nitrogen oxides. (i) When fossil fuel alone is 
combusted, the NOX emission limit for fossil fuel in Sec.  
60.44b(a) applies.
    (ii) When fossil fuel and chemical by-product waste are 
simultaneously combusted, the NOX emission limit is 473 ng/J 
(1.1 lb/MMBtu), and the air ratio control damper tee handle shall be at 
a minimum of 5 inches (12.7 centimeters) out of the boiler, and the 
flue gas recirculation line shall be operated at a minimum of 10 
percent open as indicated by its valve opening position indicator.
    (3) Emission monitoring for nitrogen oxides. (i) The air ratio 
control damper tee handle setting and the flue gas recirculation line 
valve opening position indicator setting shall be recorded during each 
8-hour operating shift.
    (ii) The NOX emission limit shall be determined by the 
compliance and performance test methods and procedures for 
NOX in Sec.  60.46b.
    (iii) The monitoring of the NOX emission limit shall be 
performed in accordance with Sec.  60.48b.
    (4) Reporting and recordkeeping requirements. (i) The owner or 
operator of Boiler No. 100 shall submit a report on any excursions from 
the limits required by paragraph (b)(2) of this section to the 
Administrator with the quarterly report required by Sec.  60.49b(i).
    (ii) The owner or operator of Boiler No. 100 shall keep records of 
the monitoring required by paragraph (b)(3) of this section for a 
period of 2 years following the date of such record.
    (iii) The owner of operator of Boiler No. 100 shall perform all the 
applicable reporting and recordkeeping requirements of Sec.  60.49b.
    (u) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant 
in Elkton, Virginia. (1) This paragraph (u) applies only to the 
pharmaceutical manufacturing facility, commonly referred to as the 
Stonewall Plant, located at Route 340 South, in Elkton, Virginia 
(``site'') and only to the natural gas-fired boilers installed as part 
of the powerhouse conversion required pursuant to 40 CFR 52.2454(g). 
The requirements of this paragraph shall apply, and the requirements of 
Sec. Sec.  60.40b through 60.49b(t) shall not apply, to the natural 
gas-fired boilers installed pursuant to 40 CFR 52.2454(g).
    (i) The site shall equip the natural gas-fired boilers with low 
NOX technology.
    (ii) The site shall install, calibrate, maintain, and operate a 
continuous monitoring and recording system for measuring NOX 
emissions discharged to the atmosphere and opacity using a continuous 
emissions monitoring system or a predictive emissions monitoring 
system.

[[Page 6367]]

    (iii) Within 180 days of the completion of the powerhouse 
conversion, as required by 40 CFR 52.2454, the site shall perform a 
performance test to quantify criteria pollutant emissions.
    (2) [Reserved]
    (v) The owner or operator of an affected facility may submit 
electronic quarterly reports for SO2 and/or NOX 
and/or opacity in lieu of submitting the written reports required under 
paragraphs (h), (i), (j), (k) or (l) of this section. The format of 
each quarterly electronic report shall be coordinated with the 
permitting authority. The electronic report(s) shall be submitted no 
later than 30 days after the end of the calendar quarter and shall be 
accompanied by a certification statement from the owner or operator, 
indicating whether compliance with the applicable emission standards 
and minimum data requirements of this subpart was achieved during the 
reporting period. Before submitting reports in the electronic format, 
the owner or operator shall coordinate with the permitting authority to 
obtain their agreement to submit reports in this alternative format.
    (w) The reporting period for the reports required under this 
subpart is each 6 month period. All reports shall be submitted to the 
Administrator and shall be postmarked by the 30th day following the end 
of the reporting period.
    (x) Facility-specific NOX standard for Weyerhaeuser 
Company's No. 2 Power Boiler located in New Bern, North Carolina:
    (1) Standard for nitrogen oxides. (i) When fossil fuel alone is 
combusted, the NOX emission limit for fossil fuel in Sec.  
60.44b(a) applies.
    (ii) When fossil fuel and chemical by-product waste are 
simultaneously combusted, the NOX emission limit is 215 ng/J 
(0.5 lb/MMBtu).
    (2) Emission monitoring for nitrogen oxides. (i) The NOX 
emissions shall be determined by the compliance and performance test 
methods and procedures for NOX in Sec.  60.46b.
    (ii) The monitoring of the NOX emissions shall be 
performed in accordance with Sec.  60.48b.
    (3) Reporting and recordkeeping requirements. (i) The owner or 
operator of the No. 2 Power Boiler shall submit a report on any 
excursions from the limits required by paragraph (x)(2) of this section 
to the Administrator with the quarterly report required by Sec.  
60.49b(i).
    (ii) The owner or operator of the No. 2 Power Boiler shall keep 
records of the monitoring required by paragraph (x)(3) of this section 
for a period of 2 years following the date of such record.
    (iii) The owner or operator of the No. 2 Power Boiler shall perform 
all the applicable reporting and recordkeeping requirements of Sec.  
60.49b.
    (y) Facility-specific NOX standard for INEOS USA's AOGI 
located in Lima, Ohio:
    (1) Standard for NOX. (i) When fossil fuel alone is 
combusted, the NOX emission limit for fossil fuel in Sec.  
60.44b(a) applies.
    (ii) When fossil fuel and chemical byproduct/waste are 
simultaneously combusted, the NOX emission limit is 645 ng/J 
(1.5 lb/MMBtu).
    (2) Emission monitoring for NOX. (i) The NOX 
emissions shall be determined by the compliance and performance test 
methods and procedures for NOX in Sec.  60.46b.
    (ii) The monitoring of the NOX emissions shall be 
performed in accordance with Sec.  60.48b.
    (3) Reporting and recordkeeping requirements. (i) The owner or 
operator of the AOGI shall submit a report on any excursions from the 
limits required by paragraph (y)(2) of this section to the 
Administrator with the quarterly report required by paragraph (i) of 
this section.
    (ii) The owner or operator of the AOGI shall keep records of the 
monitoring required by paragraph (y)(3) of this section for a period of 
2 years following the date of such record.
    (iii) The owner or operator of the AOGI shall perform all the 
applicable reporting and recordkeeping requirements of this section.

Subpart Dc--[Amended]

    6. Subpart Dc is revised to read as follows:
Subpart Dc--Standards of Performance for Small Industrial--Commercial--
Institutional Steam Generating Units
Sec.
60.40c Applicability and delegation of authority.
60.41c Definitions.
60.42c Standard for sulfur dioxide (SO2).
60.43c Standard for particulate matter (PM).
60.44c Compliance and performance test methods and procedures for 
sulfur dioxide.
60.45c Compliance and performance test methods and procedures for 
particulate matter.
60.46c Emission monitoring for sulfur dioxide.
60.47c Emission monitoring for particulate matter.
60.48c Reporting and recordkeeping requirements.

Subpart Dc--Standards of Performance for Small Industrial--
Commercial--Institutional Steam Generating Units


Sec.  60.40c  Applicability and delegation of authority.

    (a) Except as provided in paragraph (d) of this section, the 
affected facility to which this subpart applies is each steam 
generating unit for which construction, modification, or reconstruction 
is commenced after June 9, 1989 and that has a maximum design heat 
input capacity of 29 megawatts (MW) (100 million British thermal units 
per hour (MMBtu/hr)) or less, but greater than or equal to 2.9 MW (10 
MMBtu/hr).
    (b) In delegating implementation and enforcement authority to a 
State under section 111(c) of the Clean Air Act, Sec.  60.48c(a)(4) 
shall be retained by the Administrator and not transferred to a State.
    (c) Steam generating units that meet the applicability requirements 
in paragraph (a) of this section are not subject to the sulfur dioxide 
(SO2) or particulate matter (PM) emission limits, 
performance testing requirements, or monitoring requirements under this 
subpart (Sec. Sec.  60.42c, 60.43c, 60.44c, 60.45c, 60.46c, or 60.47c) 
during periods of combustion research, as defined in Sec.  60.41c.
    (d) Any temporary change to an existing steam generating unit for 
the purpose of conducting combustion research is not considered a 
modification under Sec.  60.14.
    (e) Heat recovery steam generators that are associated with 
combined cycle gas turbines and meet the applicability requirements of 
subpart GG or KKKK of this part are not subject to this subpart. This 
subpart will continue to apply to all other heat recovery steam 
generators that are capable of combusting more than or equal to 2.9 MW 
(10 MMBtu/hr) heat input of fossil fuel but less than or equal to 29 MW 
(100 MMBtu/hr) heat input of fossil fuel. If the heat recovery steam 
generator is subject to this subpart, only emissions resulting from 
combustion of fuels in the steam generating unit are subject to this 
subpart. (The gas turbine emissions are subject to subpart GG or KKKK, 
as applicable, of this part).
    (f) Any facility covered by subpart AAAA of this part is not 
covered by this subpart.
    (g) Any facility covered by an EPA approved State or Federal 
section 111(d)/129 plan implementing subpart BBBB of this part is not 
covered by this subpart.

[[Page 6368]]

Sec.  60.41c  Definitions.

    As used in this subpart, all terms not defined herein shall have 
the meaning given them in the Clean Air Act and in subpart A of this 
part.
    Annual capacity factor means the ratio between the actual heat 
input to a steam generating unit from an individual fuel or combination 
of fuels during a period of 12 consecutive calendar months and the 
potential heat input to the steam generating unit from all fuels had 
the steam generating unit been operated for 8,760 hours during that 12-
month period at the maximum design heat input capacity. In the case of 
steam generating units that are rented or leased, the actual heat input 
shall be determined based on the combined heat input from all 
operations of the affected facility during a period of 12 consecutive 
calendar months.
    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), 
coal refuse, and petroleum coke. Coal-derived synthetic fuels derived 
from coal for the purposes of creating useful heat, including but not 
limited to solvent refined coal, gasified coal, coal-oil mixtures, and 
coal-water mixtures, are also included in this definition for the 
purposes of this subpart.
    Coal refuse means any by-product of coal mining or coal cleaning 
operations with an ash content greater than 50 percent (by weight) and 
a heating value less than 13,900 kilojoules per kilogram (kJ/kg) (6,000 
Btu per pound (Btu/lb) on a dry basis.
    Cogeneration steam generating unit means a steam generating unit 
that simultaneously produces both electrical (or mechanical) and 
thermal energy from the same primary energy source.
    Combined cycle system means a system in which a separate source 
(such as a stationary gas turbine, internal combustion engine, or kiln) 
provides exhaust gas to a steam generating unit.
    Combustion research means the experimental firing of any fuel or 
combination of fuels in a steam generating unit for the purpose of 
conducting research and development of more efficient combustion or 
more effective prevention or control of air pollutant emissions from 
combustion, provided that, during these periods of research and 
development, the heat generated is not used for any purpose other than 
preheating combustion air for use by that steam generating unit (i.e., 
the heat generated is released to the atmosphere without being used for 
space heating, process heating, driving pumps, preheating combustion 
air for other units, generating electricity, or any other purpose).
    Conventional technology means wet flue gas desulfurization 
technology, dry flue gas desulfurization technology, atmospheric 
fluidized bed combustion technology, and oil hydrodesulfurization 
technology.
    Distillate oil means fuel oil that complies with the specifications 
for fuel oil numbers 1 or 2, as defined by the American Society for 
Testing and Materials in ASTM D396 (incorporated by reference, see 
Sec.  60.17).
    Dry flue gas desulfurization technology means a SO2 
control system that is located between the steam generating unit and 
the exhaust vent or stack, and that removes sulfur oxides 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 reagents 
used in dry flue gas desulfurization systems include, but are not 
limited to, lime and sodium compounds.
    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 steam generating unit.
    Emerging technology means any SO2 control system that is 
not defined as a conventional technology under this section, and for 
which the owner or operator of the affected facility has received 
approval from the Administrator to operate as an emerging technology 
under Sec.  60.48c(a)(4).
    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.
    Fluidized bed combustion technology means a device wherein fuel is 
distributed onto a bed (or series of beds) of limestone aggregate (or 
other sorbent materials) for combustion; and these materials are forced 
upward in the device by the flow of combustion air and the gaseous 
products of combustion. Fluidized bed combustion technology includes, 
but is not limited to, bubbling bed units and circulating bed units.
    Fuel pretreatment means a process that removes a portion of the 
sulfur in a fuel before combustion of the fuel in a steam generating 
unit.
    Heat input means heat derived from combustion of fuel in a steam 
generating unit and does not include the heat derived from preheated 
combustion air, recirculated flue gases, or exhaust gases from other 
sources (such as stationary gas turbines, internal combustion engines, 
and kilns).
    Heat transfer medium means any material that is used to transfer 
heat from one point to another point.
    Maximum design heat input capacity means the ability of a steam 
generating unit to combust a stated maximum amount of fuel (or 
combination of fuels) on a steady state basis as determined by the 
physical design and characteristics of the steam generating unit.
    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) 
liquefied petroleum (LP) gas, as defined by the American Society for 
Testing and Materials in ASTM D1835 (incorporated by reference, see 
Sec.  60.17).
    Noncontinental area means the State of Hawaii, the Virgin Islands, 
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern 
Mariana Islands.
    Oil means crude oil or petroleum, or a liquid fuel derived from 
crude oil or petroleum, including distillate oil and residual oil.
    Potential sulfur dioxide emission rate means the theoretical 
SO2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat 
input) that would result from combusting fuel in an uncleaned state and 
without using emission control systems.
    Process heater means a device that is primarily used to heat a 
material to initiate or promote a chemical reaction in which the 
material participates as a reactant or catalyst.
    Residual oil means crude oil, fuel oil that does not comply with 
the specifications under the definition of distillate oil, and all fuel 
oil numbers 4, 5, and 6, as defined by the American Society for Testing 
and Materials in ASTM D396 (incorporated by reference, see Sec.  
60.17).
    Steam generating unit means a device that combusts any fuel and 
produces steam or heats water or any other heat transfer medium. This 
term includes any duct burner that combusts fuel and is part of a 
combined cycle system. This term does not include process heaters as 
defined in this subpart.
    Steam generating unit operating day means a 24-hour period between 
12:00

[[Page 6369]]

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 continuously for the entire 24-hour period.
    Wet flue gas desulfurization technology means an SO2 
control system that is located between the steam generating unit and 
the exhaust vent or stack, and that removes sulfur oxides from the 
combustion gases of the steam generating unit by contacting the 
combustion gases with an alkaline slurry or solution and forming a 
liquid material. This definition includes devices where the liquid 
material is subsequently converted to another form. Alkaline reagents 
used in wet flue gas desulfurization systems include, but are not 
limited to, lime, limestone, and sodium compounds.
    Wet scrubber system means any emission control device that mixes an 
aqueous stream or slurry with the exhaust gases from a steam generating 
unit to control emissions of PM or SO2.
    Wood means wood, wood residue, bark, or any derivative fuel or 
residue thereof, in any form, including but not limited to sawdust, 
sanderdust, wood chips, scraps, slabs, millings, shavings, and 
processed pellets made from wood or other forest residues.


Sec.  60.42c  Standard for sulfur dioxide (SO2).

    (a) Except as provided in paragraphs (b), (c), and (e) of this 
section, on and after the date on which the performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, the owner or operator of an affected facility that 
combusts only coal shall neither: Cause to be discharged into the 
atmosphere from the affected facility any gases that contain 
SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 
percent (0.10) of the potential SO2 emission rate (90 
percent reduction), nor cause to be discharged into the atmosphere from 
the affected facility any gases that contain SO2 in excess 
of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is combusted with other 
fuels, the affected facility shall neither: Cause to be discharged into 
the atmosphere from the affected facility any gases that contain 
SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 
percent (0.10) of the potential SO2 emission rate (90 
percent reduction), nor cause to be discharged into the atmosphere from 
the affected facility any gases that contain SO2 in excess 
of the emission limit is determined pursuant to paragraph (e)(2) of 
this section.
    (b) Except as provided in paragraphs (c) and (e) of this section, 
on and after the date on which the performance test is completed or 
required to be completed under Sec.  60.8, whichever date comes first, 
the owner or operator of an affected facility that:
    (1) Combusts only coal refuse alone in a fluidized bed combustion 
steam generating unit shall neither:
    (i) Cause to be discharged into the atmosphere from that affected 
facility any gases that contain SO2 in excess of 87 ng/J 
(0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential 
SO2 emission rate (80 percent reduction); nor
    (ii) Cause to be discharged into the atmosphere from that affected 
facility any gases that contain SO2 in excess of 520 ng/J 
(1.2 lb/MMBtu) heat input. If coal is fired with coal refuse, the 
affected facility is subject to paragraph (a) of this section. If oil 
or any other fuel (except coal) is fired with coal refuse, the affected 
facility is subject to the 87 ng/J (0.20 lb/MMBtu) heat input 
SO2 emissions limit or the 90 percent SO2 
reduction requirement specified in paragraph (a) of this section and 
the emission limit is determined pursuant to paragraph (e)(2) of this 
section.
    (2) Combusts only coal and that uses an emerging technology for the 
control of SO2 emissions shall neither:
    (i) Cause to be discharged into the atmosphere from that affected 
facility any gases that contain SO2 in excess of 50 percent 
(0.50) of the potential SO2 emission rate (50 percent 
reduction); nor
    (ii) Cause to be discharged into the atmosphere from that affected 
facility any gases that contain SO2 in excess of 260 ng/J 
(0.60 lb/MMBtu) heat input. If coal is combusted with other fuels, the 
affected facility is subject to the 50 percent SO2 reduction 
requirement specified in this paragraph and the emission limit 
determined pursuant to paragraph (e)(2) of this section.
    (c) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that combusts 
coal, alone or in combination with any other fuel, and is listed in 
paragraphs (c)(1), (2), (3), or (4) of this section shall cause to be 
discharged into the atmosphere from that affected facility any gases 
that contain SO2 in excess of the emission limit determined 
pursuant to paragraph (e)(2) of this section. Percent reduction 
requirements are not applicable to affected facilities under paragraphs 
(c)(1), (2), (3), or (4).
    (1) Affected facilities that have a heat input capacity of 22 MW 
(75 MMBtu/hr) or less.
    (2) Affected facilities that have an annual capacity for coal of 55 
percent (0.55) or less and are subject to a federally enforceable 
requirement limiting operation of the affected facility to an annual 
capacity factor for coal of 55 percent (0.55) or less.
    (3) Affected facilities located in a noncontinental area.
    (4) Affected facilities that combust coal in a duct burner as part 
of a combined cycle system where 30 percent (0.30) or less of the heat 
entering the steam generating unit is from combustion of coal in the 
duct burner and 70 percent (0.70) or more of the heat entering the 
steam generating unit is from exhaust gases entering the duct burner.
    (d) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that combusts 
oil shall cause to be discharged into the atmosphere from that affected 
facility any gases that contain SO2 in excess of 215 ng/J 
(0.50 lb/MMBtu) heat input; or, as an alternative, no owner or operator 
of an affected facility that combusts oil shall combust oil in the 
affected facility that contains greater than 0.5 weight percent sulfur. 
The percent reduction requirements are not applicable to affected 
facilities under this paragraph.
    (e) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that combusts 
coal, oil, or coal and oil with any other fuel shall cause to be 
discharged into the atmosphere from that affected facility any gases 
that contain SO2 in excess of the following:
    (1) The percent of potential SO2 emission rate or 
numerical SO2 emission rate required under paragraph (a) or 
(b)(2) of this section, as applicable, for any affected facility that
    (i) Combusts coal in combination with any other fuel;
    (ii) Has a heat input capacity greater than 22 MW (75 MMBtu/hr); 
and
    (iii) Has an annual capacity factor for coal greater than 55 
percent (0.55); and
    (2) The emission limit determined according to the following 
formula for any affected facility that combusts coal, oil, or coal and 
oil with any other fuel:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.036


Where:

Es = SO2 emission limit, expressed in ng/J or 
lb/MMBtu heat input;

[[Page 6370]]

Ka = 520 ng/J (1.2 lb/MMBtu);
Kb = 260 ng/J (0.60 lb/MMBtu);
Kc = 215 ng/J (0.50 lb/MMBtu);
Ha = Heat input from the combustion of coal, except coal 
combusted in an affected facility subject to paragraph (b)(2) of 
this section, in Joules (J) [MMBtu];
Hb = Heat input from the combustion of coal in an 
affected facility subject to paragraph (b)(2) of this section, in J 
(MMBtu); and
Hc KaHb = Heat input from the 
combustion of oil, in J (MMBtu).

    (f) Reduction in the potential SO2 emission rate through 
fuel pretreatment is not credited toward the percent reduction 
requirement under paragraph (b)(2) of this section unless:
    (1) Fuel pretreatment results in a 50 percent (0.50) or greater 
reduction in the potential SO2 emission rate; and
    (2) Emissions from the pretreated fuel (without either combustion 
or post-combustion SO2 control) are equal to or less than 
the emission limits specified under paragraph (b)(2) of this section.
    (g) Except as provided in paragraph (h) of this section, compliance 
with the percent reduction requirements, fuel oil sulfur limits, and 
emission limits of this section shall be determined on a 30-day rolling 
average basis.
    (h) For affected facilities listed under paragraphs (h)(1), (2), or 
(3) of this section, compliance with the emission limits or fuel oil 
sulfur limits under this section may be determined based on a 
certification from the fuel supplier, as described under Sec.  
60.48c(f), as applicable.
    (1) Distillate oil-fired affected facilities with heat input 
capacities between 2.9 and 29 MW (10 and 100 MMBtu/hr).
    (2) Residual oil-fired affected facilities with heat input 
capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).
    (3) Coal-fired facilities with heat input capacities between 2.9 
and 8.7 MW (10 and 30 MMBtu/hr).
    (i) The SO2 emission limits, fuel oil sulfur limits, and 
percent reduction requirements under this section apply at all times, 
including periods of startup, shutdown, and malfunction.
    (j) Only the heat input supplied to the affected facility from the 
combustion of coal and oil is counted under this section. No credit is 
provided for the heat input to the affected facility from wood or other 
fuels or for heat derived from exhaust gases from other sources, such 
as stationary gas turbines, internal combustion engines, and kilns.


Sec.  60.43c  Standard for particulate matter (PM).

    (a) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that 
commenced construction, reconstruction, or modification on or before 
February 28, 2005, that combusts coal or combusts mixtures of coal with 
other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/hr) or 
greater, shall cause to be discharged into the atmosphere from that 
affected facility any gases that contain PM in excess of the following 
emission limits:
    (1) 22 ng/J (0.051 lb/MMBtu) heat input if the affected facility 
combusts only coal, or combusts coal with other fuels and has an annual 
capacity factor for the other fuels of 10 percent (0.10) or less.
    (2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility 
combusts coal with other fuels, has an annual capacity factor for the 
other fuels greater than 10 percent (0.10), and is subject to a 
federally enforceable requirement limiting operation of the affected 
facility to an annual capacity factor greater than 10 percent (0.10) 
for fuels other than coal.
    (b) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that 
commenced construction, reconstruction, or modification on or before 
February 28, 2005, that combusts wood or combusts mixtures of wood with 
other fuels (except coal) and has a heat input capacity of 8.7 MW (30 
MMBtu/hr) or greater, shall cause to be discharged into the atmosphere 
from that affected facility any gases that contain PM in excess of the 
following emissions limits:
    (1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has 
an annual capacity factor for wood greater than 30 percent (0.30); or
    (2) 130 ng/J (0.30 lb/MMBtu) heat input if the affected facility 
has an annual capacity factor for wood of 30 percent (0.30) or less and 
is subject to a federally enforceable requirement limiting operation of 
the affected facility to an annual capacity factor for wood of 30 
percent (0.30) or less.
    (c) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that combusts 
coal, wood, or oil and has a heat input capacity of 8.7 MW (30 MMBtu/
hr) or greater shall cause to be discharged into the atmosphere from 
that affected facility any gases that exhibit greater than 20 percent 
opacity (6-minute average), except for one 6-minute period per hour of 
not more than 27 percent opacity.
    (d) The PM and opacity standards under this section apply at all 
times, except during periods of startup, shutdown, or malfunction.
    (e)(1) On and after the date on which the initial performance test 
is completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
commences construction, reconstruction, or modification after February 
28, 2005, and that combusts coal, oil, wood, a mixture of these fuels, 
or a mixture of these fuels with any other fuels and has a heat input 
capacity of 8.7 MW (30 MMBtu/hr) or greater shall cause to be 
discharged into the atmosphere from that affected facility any gases 
that contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input, 
except as provided in paragraphs (e)(2), (e)(3), and (e)(4) of this 
section.
    (2) As an alternative to meeting the requirements of paragraph 
(e)(1) of this section, the owner or operator of an affected facility 
for which modification commenced after February 28, 2005, may elect to 
meet the requirements of this paragraph. On and after the date on which 
the initial performance test is completed or required to be completed 
under Sec.  60.8, whichever date comes first, no owner or operator of 
an affected facility that commences modification after February 28, 
2005 shall cause to be discharged into the atmosphere from that 
affected facility any gases that contain PM in excess of both:
    (i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion 
of coal, oil, wood, a mixture of these fuels, or a mixture of these 
fuels with any other fuels; and
    (ii) 0.2 percent of the combustion concentration (99.8 percent 
reduction) when combusting coal, oil, wood, a mixture of these fuels, 
or a mixture of these fuels with any other fuels.
    (3) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
commences modification after February 28, 2005, and that combusts over 
30 percent wood (by heat input) on an annual basis and has a heat input 
capacity of 8.7 MW (30 MMBtu/hr) or greater shall cause to be 
discharged into the atmosphere from that affected facility any gases 
that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
    (4) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no

[[Page 6371]]

owner or operator of an affected facility that commences construction, 
reconstruction, or modification after February 28, 2005, and that 
combusts only oil that contains no more than 0.50 weight percent sulfur 
or a mixture of 0.50 weight percent sulfur oil with other fuels not 
subject to a PM standard under Sec.  60.43c and not using a post 
combustion technology (except a wet scrubber) to reduce PM or 
SO2 emissions is subject to the PM limit in this section.


Sec.  60.44c  Compliance and performance test methods and procedures 
for sulfur dioxide.

    (a) Except as provided in paragraphs (g) and (h) of this section 
and Sec.  60.8(b), performance tests required under Sec.  60.8 shall be 
conducted following the procedures specified in paragraphs (b), (c), 
(d), (e), and (f) of this section, as applicable. Section 60.8(f) does 
not apply to this section. The 30-day notice required in Sec.  60.8(d) 
applies only to the initial performance test unless otherwise specified 
by the Administrator.
    (b) The initial performance test required under Sec.  60.8 shall be 
conducted over 30 consecutive operating days of the steam generating 
unit. Compliance with the percent reduction requirements and 
SO2 emission limits under Sec.  60.42c shall be determined 
using a 30-day average. The first operating day included in the initial 
performance test shall be scheduled within 30 days after achieving the 
maximum production rate at which the affect facility will be operated, 
but not later than 180 days after the initial startup of the facility. 
The steam generating unit load during the 30-day period does not have 
to be the maximum design heat input capacity, but must be 
representative of future operating conditions.
    (c) After the initial performance test required under paragraph (b) 
of this section and Sec.  60.8, compliance with the percent reduction 
requirements and SO2 emission limits under Sec.  60.42c is 
based on the average percent reduction and the average SO2 
emission rates for 30 consecutive steam generating unit operating days. 
A separate performance test is completed at the end of each steam 
generating unit operating day, and a new 30-day average percent 
reduction and SO2 emission rate are calculated to show 
compliance with the standard.
    (d) If only coal, only oil, or a mixture of coal and oil is 
combusted in an affected facility, the procedures in Method 19 of 
appendix A of this part are used to determine the hourly SO2 
emission rate (Eho) and the 30-day average SO2 
emission rate (Eao). The hourly averages used to compute the 
30-day averages are obtained from the CEMS. Method 19 of appendix A of 
this part shall be used to calculate Eao when using daily 
fuel sampling or Method 6B of appendix A of this part.
    (e) If coal, oil, or coal and oil are combusted with other fuels:
    (1) An adjusted Eho (Ehoo) is used 
in Equation 19-19 of Method 19 of appendix A of this part to compute 
the adjusted Eao (Eaoo). The 
Ehoo is computed using the following formula:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.037


Where:
Ehoo = Adjusted Eho, ng/J (lb/
MMBtu);
Eho = Hourly SO2 emission rate, ng/J (lb/
MMBtu);
Ew = SO2 concentration in fuels other than 
coal and oil combusted in the affected facility, as determined by 
fuel sampling and analysis procedures in Method 9 of appendix A of 
this part, ng/J (lb/MMBtu). The value Ew for each fuel 
lot is used for each hourly average during the time that the lot is 
being combusted. The owner or operator does not have to measure 
Ew if the owner or operator elects to assume 
Ew=0.
Xk = Fraction of the total heat input from fuel 
combustion derived from coal and oil, as determined by applicable 
procedures in Method 19 of appendix A of this part.

    (2) The owner or operator of an affected facility that qualifies 
under the provisions of Sec.  60.42c(c) or (d) (where percent reduction 
is not required) does not have to measure the parameters Ew 
or Xk if the owner or operator of the affected facility 
elects to measure emission rates of the coal or oil using the fuel 
sampling and analysis procedures under Method 19 of appendix A of this 
part.
    (f) Affected facilities subject to the percent reduction 
requirements under Sec.  60.42c(a) or (b) shall determine compliance 
with the SO2 emission limits under Sec.  60.42c pursuant to 
paragraphs (d) or (e) of this section, and shall determine compliance 
with the percent reduction requirements using the following procedures:
    (1) If only coal is combusted, the percent of potential 
SO2 emission rate is computed using the following formula:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.038


Where:

%Ps = Potential SO2 emission rate, in percent;
%Rg = SO2 removal efficiency of the control 
device as determined by Method 19 of appendix A of this part, in 
percent; and
%Rf = SO2 removal efficiency of fuel 
pretreatment as determined by Method 19 of appendix A of this part, 
in percent.

    (2) If coal, oil, or coal and oil are combusted with other fuels, 
the same procedures required in paragraph (f)(1) of this section are 
used, except as provided for in the following:
    (i) To compute the %Ps, an adjusted %Rg 
(%Rgo) is computed from Eaoo from 
paragraph (e)(1) of this section and an adjusted average SO2 
inlet rate (Eaio) using the following formula:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.039


Where:

%Rgo = Adjusted %Rg, in percent;
Eaoo = Adjusted Eao, ng/J (lb/
MMBtu); and
Eaio = Adjusted average SO2 inlet 
rate, ng/J (lb/MMBtu).
    (ii) To compute Eaio, an adjusted hourly 
SO2 inlet rate (Ehio) is used. The 
Ehio is computed using the following formula:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.040


Where:

Ehio = Adjusted Ehi, ng/J (lb/
MMBtu);
Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu);
Ew = SO2 concentration in fuels other than 
coal and oil combusted in the affected facility, as determined by 
fuel sampling and analysis procedures in Method 19 of appendix A of 
this part, ng/J (lb/MMBtu). The value Ew for each fuel 
lot is used for each hourly average during the time that the lot is 
being combusted. The owner or operator does not have to measure 
Ew if the owner or operator elects to assume 
Ew = 0; and
Xk = Fraction of the total heat input from fuel 
combustion derived from coal and oil, as determined by applicable 
procedures in Method 19 of appendix A of this part.

    (g) For oil-fired affected facilities where the owner or operator 
seeks to demonstrate compliance with the fuel oil sulfur limits under 
Sec.  60.42c based on shipment fuel sampling, the initial performance 
test shall consist of sampling and analyzing the oil in the initial 
tank of oil to be fired in the steam generating unit to demonstrate 
that the oil contains 0.5 weight percent sulfur or less. Thereafter, 
the owner or operator of the affected facility shall sample the oil in 
the fuel tank after each new shipment of oil is received, as described 
under Sec.  60.46c(d)(2).
    (h) For affected facilities subject to Sec.  60.42c(h)(1), (2), or 
(3) where the owner or operator seeks to demonstrate

[[Page 6372]]

compliance with the SO2 standards based on fuel supplier 
certification, the performance test shall consist of the certification, 
the certification from the fuel supplier, as described under Sec.  
60.48c(f), as applicable.
    (i) The owner or operator of an affected facility seeking to 
demonstrate compliance with the SO2 standards under Sec.  
60.42c(c)(2) shall demonstrate the maximum design heat input capacity 
of the steam generating unit by operating the steam generating unit at 
this capacity for 24 hours. This demonstration shall be made during the 
initial performance test, and a subsequent demonstration may be 
requested at any other time. If the demonstrated 24-hour average firing 
rate for the affected facility is less than the maximum design heat 
input capacity stated by the manufacturer of the affected facility, the 
demonstrated 24-hour average firing rate shall be used to determine the 
annual capacity factor for the affected facility; otherwise, the 
maximum design heat input capacity provided by the manufacturer shall 
be used.
    (j) The owner or operator of an affected facility shall use all 
valid SO2 emissions data in calculating %Ps and 
Eho under paragraphs (d), (e), or (f) of this section, as 
applicable, whether or not the minimum emissions data requirements 
under Sec.  60.46c(f) are achieved. All valid emissions data, including 
valid data collected during periods of startup, shutdown, and 
malfunction, shall be used in calculating %Ps or 
Eho pursuant to paragraphs (d), (e), or (f) of this section, 
as applicable.


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

    (a) The owner or operator of an affected facility subject to the PM 
and/or opacity standards under Sec.  60.43c shall conduct an initial 
performance test as required under Sec.  60.8, and shall conduct 
subsequent performance tests as requested by the Administrator, to 
determine compliance with the standards using the following procedures 
and reference methods, except as specified in paragraph (c) of this 
section.
    (1) Method 1 of appendix A of this part shall be used to select the 
sampling site and the number of traverse sampling points.
    (2) Method 3 of appendix A of this part shall be used for gas 
analysis when applying Method 5, 5B, or 17 of appendix A of this part.
    (3) Method 5, 5B, or 17 of appendix A of this part shall be used to 
measure the concentration of PM as follows:
    (i) Method 5 of appendix A of this part may be used only at 
affected facilities without wet scrubber systems.
    (ii) Method 17 of appendix A of this part may be used at affected 
facilities with or without wet scrubber systems provided the stack gas 
temperature does not exceed a temperature of 160 [deg]C (320 [deg]F). 
The procedures of Sections 8.1 and 11.1 of Method 5B of appendix A of 
this part may be used in Method 17 of appendix A of this part only if 
Method 17 of appendix A of this part is used in conjunction with a wet 
scrubber system. Method 17 of appendix A of this part shall not be used 
in conjunction with a wet scrubber system if the effluent is saturated 
or laden with water droplets.
    (iii) Method 5B of appendix A of this part may be used in 
conjunction with a wet scrubber system.
    (4) The sampling time for each run shall be at least 120 minutes 
and the minimum sampling volume shall be 1.7 dry standard cubic meters 
(dscm) [60 dry standard cubic feet (dscf)] except that smaller sampling 
times or volumes may be approved by the Administrator when necessitated 
by process variables or other factors.
    (5) For Method 5 or 5B of appendix A of this part, the temperature 
of the sample gas in the probe and filter holder shall be monitored and 
maintained at 16014 [deg]C (32025 [deg]F).
    (6) For determination of PM emissions, an oxygen (O2) or 
carbon dioxide (CO2) measurement shall be obtained 
simultaneously with each run of Method 5, 5B, or 17 of appendix A of 
this part by traversing the duct at the same sampling location.
    (7) For each run using Method 5, 5B, or 17 of appendix A of this 
part, the emission rates expressed in ng/J (lb/MMBtu) heat input shall 
be determined using:
    (i) The O2 or CO2 measurements and PM 
measurements obtained under this section,
    (ii) The dry basis F factor, and
    (iii) The dry basis emission rate calculation procedure contained 
in Method 19 of appendix A of this part.
    (8) Method 9 of appendix A of this part (6-minute average of 24 
observations) shall be used for determining the opacity of stack 
emissions.
    (b) The owner or operator of an affected facility seeking to 
demonstrate compliance with the PM standards under Sec.  60.43c(b)(2) 
shall demonstrate the maximum design heat input capacity of the steam 
generating unit by operating the steam generating unit at this capacity 
for 24 hours. This demonstration shall be made during the initial 
performance test, and a subsequent demonstration may be requested at 
any other time. If the demonstrated 24-hour average firing rate for the 
affected facility is less than the maximum design heat input capacity 
stated by the manufacturer of the affected facility, the demonstrated 
24-hour average firing rate shall be used to determine the annual 
capacity factor for the affected facility; otherwise, the maximum 
design heat input capacity provided by the manufacturer shall be used.
    (c) In place of PM testing with EPA Reference Method 5, 5B, or 17 
of appendix A of this part, an owner or operator may elect to install, 
calibrate, maintain, and operate a CEMS for monitoring PM emissions 
discharged to the atmosphere and record the output of the system. The 
owner or operator of an affected facility who elects to continuously 
monitor PM emissions instead of conducting performance testing using 
EPA Method 5, 5B, or 17 of appendix A of this part shall install, 
calibrate, maintain, and operate a CEMS and shall comply with the 
requirements specified in paragraphs (c)(1) through (c)(13) of this 
section.
    (1) Notify the Administrator 1 month before starting use of the 
system.
    (2) Notify the Administrator 1 month before stopping use of the 
system.
    (3) The monitor shall be installed, evaluated, and operated in 
accordance with Sec.  60.13 of subpart A of this part.
    (4) The initial performance evaluation shall be completed no later 
than 180 days after the date of initial startup of the affected 
facility, as specified under Sec.  60.8 of subpart A of this part or 
within 180 days of notification to the Administrator of use of CEMS if 
the owner or operator was previously determining compliance by Method 
5, 5B, or 17 of appendix A of this part performance tests, whichever is 
later.
    (5) The owner or operator of an affected facility shall conduct an 
initial performance test for PM emissions as required under Sec.  60.8 
of subpart A of this part. Compliance with the PM emission limit shall 
be determined by using the CEMS specified in paragraph (d) of this 
section to measure PM and calculating a 24-hour block arithmetic 
average emission concentration using EPA Reference Method 19 of 
appendix A of this part, section 4.1.
    (6) Compliance with the PM emission limit shall be determined based 
on the 24-hour daily (block) average of the hourly arithmetic average 
emission concentrations using CEMS outlet data.

[[Page 6373]]

    (7) At a minimum, valid CEMS hourly averages shall be obtained as 
specified in paragraph (d)(7)(i) of this section for 75 percent of the 
total operating hours per 30-day rolling average.
    (i) At least two data points per hour shall be used to calculate 
each 1-hour arithmetic average.
    (ii) [Reserved]
    (8) The 1-hour arithmetic averages required under paragraph (d)(7) 
of this section shall be expressed in ng/J or lb/MMBtu heat input and 
shall be used to calculate the boiler operating day daily arithmetic 
average emission concentrations. The 1-hour arithmetic averages shall 
be calculated using the data points required under Sec.  60.13(e)(2) of 
subpart A of this part.
    (9) All valid CEMS data shall be used in calculating average 
emission concentrations even if the minimum CEMS data requirements of 
paragraph (d)(7) of this section are not met.
    (10) The CEMS shall be operated according to Performance 
Specification 11 in appendix B of this part.
    (11) During the correlation testing runs of the CEMS required by 
Performance Specification 11 in appendix B of this part, PM and 
O2 (or CO2) data shall be collected concurrently 
(or within a 30-to 60-minute period) by both the continuous emission 
monitors and the test methods specified in paragraph (d)(7)(i) of this 
section.
    (i) For PM, EPA Reference Method 5, 5B, or 17 of appendix A of this 
part shall be used.
    (ii) For O2 (or CO2), EPA reference Method 3, 
3A, or 3B of appendix A of this part, as applicable shall be used.
    (12) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with procedure 2 in appendix F 
of this part. Relative Response Audit's must be performed annually and 
Response Correlation Audits must be performed every 3 years.
    (13) When PM emissions data are not obtained because of CEMS 
breakdowns, repairs, calibration checks, and zero and span adjustments, 
emissions data shall be obtained by using other monitoring systems as 
approved by the Administrator or EPA Reference Method 19 of appendix A 
of this part to provide, as necessary, valid emissions data for a 
minimum of 75 percent of total operating hours on a 30-day rolling 
average.
    (d) The owner or operator of an affected facility seeking to 
demonstrate compliance under Sec.  60.43c(e)(4) shall follow the 
applicable procedures under Sec.  60.48c(f). For residual oil-fired 
affected facilities, fuel supplier certifications are only allowed for 
facilities with heat input capacities between 2.9 and 8.7 MW (10 to 30 
MMBtu/hr).


Sec.  60.46c  Emission monitoring for sulfur dioxide

    (a) Except as provided in paragraphs (d) and (e) of this section, 
the owner or operator of an affected facility subject to the 
SO2 emission limits under Sec.  60.42c shall install, 
calibrate, maintain, and operate a CEMS for measuring SO2 
concentrations and either O2 or CO2 
concentrations at the outlet of the SO2 control device (or 
the outlet of the steam generating unit if no SO2 control 
device is used), and shall record the output of the system. The owner 
or operator of an affected facility subject to the percent reduction 
requirements under Sec.  60.42c shall measure SO2 
concentrations and either O2 or CO2 
concentrations at both the inlet and outlet of the SO2 
control device.
    (b) The 1-hour average SO2 emission rates measured by a 
CEMS shall be expressed in ng/J or lb/MMBtu heat input and shall be 
used to calculate the average emission rates under Sec.  60.42c. Each 
1-hour average SO2 emission rate must be based on at least 
30 minutes of operation and include at least 2 data points representing 
two 15-minute periods. Hourly SO2 emission rates are not 
calculated if the affected facility is operated less than 30 minutes in 
a 1-hour period and are not counted toward determination of a steam 
generating unit operating day.
    (c) The procedures under Sec.  60.13 shall be followed for 
installation, evaluation, and operation of the CEMS.
    (1) All CEMS shall be operated in accordance with the applicable 
procedures under Performance Specifications 1, 2, and 3 of appendix B 
of this part.
    (2) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with Procedure 1 of appendix F 
of this part.
    (3) For affected facilities subject to the percent reduction 
requirements under Sec.  60.42c, the span value of the SO2 
CEMS at the inlet to the SO2 control device shall be 125 
percent of the maximum estimated hourly potential SO2 
emission rate of the fuel combusted, and the span value of the 
SO2 CEMS at the outlet from the SO2 control 
device shall be 50 percent of the maximum estimated hourly potential 
SO2 emission rate of the fuel combusted.
    (4) For affected facilities that are not subject to the percent 
reduction requirements of Sec.  60.42c, the span value of the 
SO2 CEMS at the outlet from the SO2 control 
device (or outlet of the steam generating unit if no SO2 
control device is used) shall be 125 percent of the maximum estimated 
hourly potential SO2 emission rate of the fuel combusted.
    (d) As an alternative to operating a CEMS at the inlet to the 
SO2 control device (or outlet of the steam generating unit 
if no SO2 control device is used) as required under 
paragraph (a) of this section, an owner or operator may elect to 
determine the average SO2 emission rate by sampling the fuel 
prior to combustion. As an alternative to operating a CEMS at the 
outlet from the SO2 control device (or outlet of the steam 
generating unit if no SO2 control device is used) as 
required under paragraph (a) of this section, an owner or operator may 
elect to determine the average SO2 emission rate by using 
Method 6B of appendix A of this part. Fuel sampling shall be conducted 
pursuant to either paragraph (d)(1) or (d)(2) of this section. Method 
6B of appendix A of this part shall be conducted pursuant to paragraph 
(d)(3) of this section.
    (1) For affected facilities combusting coal or oil, coal or oil 
samples shall be collected daily in an as-fired condition at the inlet 
to the steam generating unit and analyzed for sulfur content and heat 
content according to Method 19 of appendix A of this part. Method 19 of 
appendix A of this part provides procedures for converting these 
measurements into the format to be used in calculating the average 
SO2 input rate.
    (2) As an alternative fuel sampling procedure for affected 
facilities combusting oil, oil samples may be collected from the fuel 
tank for each steam generating unit immediately after the fuel tank is 
filled and before any oil is combusted. The owner or operator of the 
affected facility shall analyze the oil sample to determine the sulfur 
content of the oil. If a partially empty fuel tank is refilled, a new 
sample and analysis of the fuel in the tank would be required upon 
filling. Results of the fuel analysis taken after each new shipment of 
oil is received shall be used as the daily value when calculating the 
30-day rolling average until the next shipment is received. If the fuel 
analysis shows that the sulfur content in the fuel tank is greater than 
0.5 weight percent sulfur, the owner or operator shall ensure that the 
sulfur content of subsequent oil shipments is low enough to cause the 
30-day rolling average sulfur content to be 0.5 weight percent sulfur 
or less.
    (3) Method 6B of appendix A of this part may be used in lieu of 
CEMS to measure SO2 at the inlet or outlet of the 
SO2 control system. An initial

[[Page 6374]]

stratification test is required to verify the adequacy of the Method 6B 
of appendix A of this part sampling location. The stratification test 
shall consist of three paired runs of a suitable SO2 and 
CO2 measurement train operated at the candidate location and 
a second similar train operated according to the procedures in Sec.  
3.2 and the applicable procedures in section 7 of Performance 
Specification 2 of appendix B of this part. Method 6B of appendix A of 
this part, Method 6A of appendix A of this part, or a combination of 
Methods 6 and 3 of appendix A of this part or Methods 6C and 3A of 
appendix A of this part are suitable measurement techniques. If Method 
6B of appendix A of this part is used for the second train, sampling 
time and timer operation may be adjusted for the stratification test as 
long as an adequate sample volume is collected; however, both sampling 
trains are to be operated similarly. For the location to be adequate 
for Method 6B of appendix A of this part 24-hour tests, the mean of the 
absolute difference between the three paired runs must be less than 10 
percent (0.10).
    (e) The monitoring requirements of paragraphs (a) and (d) of this 
section shall not apply to affected facilities subject to Sec.  
60.42c(h)(1), (2), or (3) where the owner or operator of the affected 
facility seeks to demonstrate compliance with the SO2 
standards based on fuel supplier certification, as described under 
Sec.  60.48c(f), as applicable.
    (f) The owner or operator of an affected facility operating a CEMS 
pursuant to paragraph (a) of this section, or conducting as-fired fuel 
sampling pursuant to paragraph (d)(1) of this section, shall obtain 
emission data for at least 75 percent of the operating hours in at 
least 22 out of 30 successive steam generating unit operating days. If 
this minimum data requirement is not met with a single monitoring 
system, the owner or operator of the affected facility shall supplement 
the emission data with data collected with other monitoring systems as 
approved by the Administrator.


Sec.  60.47c  Emission monitoring for particulate matter.

    (a) Except as provided in paragraphs (c) and (d) of this section, 
the owner or operator of an affected facility combusting coal, oil, or 
wood that is subject to the opacity standards under Sec.  60.43c shall 
install, calibrate, maintain, and operate a COMS for measuring the 
opacity of the emissions discharged to the atmosphere and record the 
output of the system.
    (b) All COMS for measuring opacity shall be operated in accordance 
with the applicable procedures under Performance Specification 1 of 
appendix B of this part. The span value of the opacity COMS shall be 
between 60 and 80 percent.
    (c) Affected facilities that burn only distillate oil that contains 
no more than 0.5 weight percent sulfur and/or liquid or gaseous fuels 
with potential sulfur dioxide emission rates of 26 ng/J (0.06 lb/MMBtu) 
heat input or less and that do not use a post combustion technology to 
reduce SO2 or PM emissions are not required to operate a 
CEMS for measuring opacity if they follow the applicable procedures 
under Sec.  60.48c(f).
    (d) Owners or operators complying with the PM emission limit by 
using a PM CEMS monitor instead of monitoring opacity must calibrate, 
maintain, and operate a CEMS, and record the output of the system, for 
PM emissions discharged to the atmosphere as specified in Sec.  
60.45c(d). The CEMS specified in paragraph Sec.  60.45c(d) shall be 
operated and data recorded during all periods of operation of the 
affected facility except for CEMS breakdowns and repairs. Data is 
recorded during calibration checks, and zero and span adjustments.


Sec.  60.48c  Reporting and recordkeeping requirements.

    (a) The owner or operator of each affected facility shall submit 
notification of the date of construction or reconstruction and actual 
startup, as provided by Sec.  60.7 of this part. This notification 
shall include:
    (1) The design heat input capacity of the affected facility and 
identification of fuels to be combusted in the affected facility.
    (2) If applicable, a copy of any federally enforceable requirement 
that limits the annual capacity factor for any fuel or mixture of fuels 
under Sec.  60.42c, or Sec.  60.43c.
    (3) The annual capacity factor at which the owner or operator 
anticipates operating the affected facility based on all fuels fired 
and based on each individual fuel fired.
    (4) Notification if an emerging technology will be used for 
controlling SO2 emissions. The Administrator will examine 
the description of the control device and will determine whether the 
technology qualifies as an emerging technology. In making this 
determination, the Administrator may require the owner or operator of 
the affected facility to submit additional information concerning the 
control device. The affected facility is subject to the provisions of 
Sec.  60.42c(a) or (b)(1), unless and until this determination is made 
by the Administrator.
    (b) The owner or operator of each affected facility subject to the 
SO2 emission limits of Sec.  60.42c, or the PM or opacity 
limits of Sec.  60.43c, shall submit to the Administrator the 
performance test data from the initial and any subsequent performance 
tests and, if applicable, the performance evaluation of the CEMS and/or 
COMS using the applicable performance specifications in appendix B of 
this part.
    (c) The owner or operator of each coal-fired, oil-fired, or wood-
fired affected facility subject to the opacity limits under Sec.  
60.43c(c) shall submit excess emission reports for any excess emissions 
from the affected facility that occur during the reporting period.
    (d) The owner or operator of each affected facility subject to the 
SO2 emission limits, fuel oil sulfur limits, or percent 
reduction requirements under Sec.  60.42c shall submit reports to the 
Administrator.
    (e) The owner or operator of each affected facility subject to the 
SO2 emission limits, fuel oil sulfur limits, or percent 
reduction requirements under Sec.  60.42c shall keep records and submit 
reports as required under paragraph (d) of this section, including the 
following information, as applicable.
    (1) Calendar dates covered in the reporting period.
    (2) Each 30-day average SO2 emission rate (ng/J or lb/
MMBtu), or 30-day average sulfur content (weight percent), calculated 
during the reporting period, ending with the last 30-day period; 
reasons for any noncompliance with the emission standards; and a 
description of corrective actions taken.
    (3) Each 30-day average percent of potential SO2 
emission rate calculated during the reporting period, ending with the 
last 30-day period; reasons for any noncompliance with the emission 
standards; and a description of the corrective actions taken.
    (4) Identification of any steam generating unit operating days for 
which SO2 or diluent (O2 or CO2) data 
have not been obtained by an approved method for at least 75 percent of 
the operating hours; justification for not obtaining sufficient data; 
and a description of corrective actions taken.
    (5) Identification of any times when emissions data have been 
excluded from the calculation of average emission rates; justification 
for excluding data; and a description of corrective actions taken if 
data have been excluded for periods other than those during which coal 
or oil were not combusted in the steam generating unit.

[[Page 6375]]

    (6) Identification of the F factor used in calculations, method of 
determination, and type of fuel combusted.
    (7) Identification of whether averages have been obtained based on 
CEMS rather than manual sampling methods.
    (8) If a CEMS is used, identification of any times when the 
pollutant concentration exceeded the full span of the CEMS.
    (9) If a CEMS is used, description of any modifications to the CEMS 
that could affect the ability of the CEMS to comply with Performance 
Specifications 2 or 3 of appendix B of this part.
    (10) If a CEMS is used, results of daily CEMS drift tests and 
quarterly accuracy assessments as required under appendix F, Procedure 
1 of this part.
    (11) If fuel supplier certification is used to demonstrate 
compliance, records of fuel supplier certification is used to 
demonstrate compliance, records of fuel supplier certification as 
described under paragraph (f)(1), (2), (3), or (4) of this section, as 
applicable. In addition to records of fuel supplier certifications, the 
report shall include a certified statement signed by the owner or 
operator of the affected facility that the records of fuel supplier 
certifications submitted represent all of the fuel combusted during the 
reporting period.
    (f) Fuel supplier certification shall include the following 
information:
    (1) For distillate oil:
    (i) The name of the oil supplier;
    (ii) A statement from the oil supplier that the oil complies with 
the specifications under the definition of distillate oil in Sec.  
60.41c; and
    (iii) The sulfur content of the oil.
    (2) For residual oil:
    (i) The name of the oil supplier;
    (ii) The location of the oil when the sample was drawn for analysis 
to determine the sulfur content of the oil, specifically including 
whether the oil was sampled as delivered to the affected facility, or 
whether the sample was drawn from oil in storage at the oil supplier's 
or oil refiner's facility, or other location;
    (iii) The sulfur content of the oil from which the shipment came 
(or of the shipment itself); and
    (iv) The method used to determine the sulfur content of the oil.
    (3) For coal:
    (i) The name of the coal supplier;
    (ii) The location of the coal when the sample was collected for 
analysis to determine the properties of the coal, specifically 
including whether the coal was sampled as delivered to the affected 
facility or whether the sample was collected from coal in storage at 
the mine, at a coal preparation plant, at a coal supplier's facility, 
or at another location. The certification shall include the name of the 
coal mine (and coal seam), coal storage facility, or coal preparation 
plant (where the sample was collected);
    (iii) The results of the analysis of the coal from which the 
shipment came (or of the shipment itself) including the sulfur content, 
moisture content, ash content, and heat content; and
    (iv) The methods used to determine the properties of the coal.
    (4) For other fuels:
    (i) The name of the supplier of the fuel;
    (ii) The potential sulfur emissions rate of the fuel in ng/J heat 
input; and
    (iii) The method used to determine the potential sulfur emissions 
rate of the fuel.
    (g)(1) Except as provided under paragraph (g)(2) of this section, 
the owner or operator of each affected facility shall record and 
maintain records of the amount of each fuel combusted during each 
operating day.
    (2) As an alternative to meeting the requirements of paragraph 
(g)(1) of this section, the owner or operator of an affected facility 
that combusts only natural gas, wood, fuels using fuel certification in 
Sec.  60.48c(f) to demonstrate compliance with the SO2 
standard, fuels not subject to an emissions standard (excluding 
opacity), or a mixture of these fuels may elect to record and maintain 
records of the amount of each fuel combusted during each calendar 
month.
    (h) The owner or operator of each affected facility subject to a 
federally enforceable requirement limiting the annual capacity factor 
for any fuel or mixture of fuels under Sec.  60.42c or Sec.  60.43c 
shall calculate the annual capacity factor individually for each fuel 
combusted. The annual capacity factor is determined on a 12-month 
rolling average basis with a new annual capacity factor calculated at 
the end of the calendar month.
    (i) All records required under this section shall be maintained by 
the owner or operator of the affected facility for a period of two 
years following the date of such record.
    (j) The reporting period for the reports required under this 
subpart is each six-month period. All reports shall be submitted to the 
Administrator and shall be postmarked by the 30th day following the end 
of the reporting period.

[FR Doc. E7-1881 Filed 2-8-07; 8:45 am]

BILLING CODE 6560-50-P
