[Federal Register Volume 73, Number 114 (Thursday, June 12, 2008)]
[Proposed Rules]
[Pages 33641-33659]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E8-12621]



[[Page 33641]]

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Part VI





Environmental Protection Agency





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40 CFR Part 60



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; Proposed Rule

Federal Register / Vol. 73, No. 114 / Thursday, June 12, 2008 / 
Proposed Rules

[[Page 33642]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2005-0031; FRL-8576-2]
RIN 2060-AO61


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing to amend the new source performance standards 
for electric utility steam generating units and industrial-commercial-
institutional steam generating units. On June 13, 2007, EPA promulgated 
amendments to the standards for steam generating units. Subsequently, 
EPA received a petition for reconsideration which it is granting to the 
extent specified in the proposed action. EPA is proposing to amend 
specific provisions in the standards for steam generating units, as 
amended, to resolve issues and questions raised by the petitioner for 
reconsideration, and to correct technical and editorial errors that 
have been identified since promulgation. In addition, EPA is requesting 
comment on the appropriate opacity standard for owners/operators of 
affected facilities using a particulate matter continuous emissions 
monitoring system to demonstrate compliance with the applicable PM 
limit.

DATES: Comments. Comments must be received on or before July 28, 2008. 
If anyone contacts EPA by June 23, 2008 requesting to speak at a public 
hearing, EPA will hold a public hearing on June 27, 2008.

ADDRESSES: Comments. Submit your comments, identified by Docket ID No. 
EPA-HQ-OAR-2005-0031, by one of the following methods:
     http://www.regulations.gov. Follow the on-line 
instructions for submitting comments.
     E-mail: [email protected].
     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. In addition, please mail a copy of your comments 
on the information collection provisions to the Office of Information 
and Regulatory Affairs, Office of Management and Budget (OMB), Attn: 
Desk Officer for EPA, 725 17th Street, NW., Washington, DC 20503. 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'' system, 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 
through http://www.regulations.gov, EPA recommends that you include 
your name and other contact information in the body of your comment as 
well as 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: 
[email protected].

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

------------------------------------------------------------------------
                                                   Examples of regulated
           Category                 NAICS \1\            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.

[[Page 33643]]

 
Any industrial, commercial, or               211  Extractors of crude
 institutional facility using                321   petroleum and natural
 a steam generating unit as                  322   gas.
 defined in 60.40b or 60.40c.                325  Manufacturers of
                                             324   lumber and wood
                                                   products.
                                                  Pulp and paper mills.
                                                  Chemical
                                                   manufacturers.
                                                  Petroleum refiners and
                                                   manufacturers of coal
                                                   products.
                                   316, 326, 339  Manufacturers of
                                                   rubber and
                                                   miscellaneous plastic
                                                   products.
                                             331  Steel works, blast
                                                   furnaces.
                                             332  Electroplating,
                                                   plating, polishing,
                                                   anodizing, and
                                                   coloring.
                                             336  Manufacturers of motor
                                                   vehicle parts and
                                                   accessories.
                                             221  Electric, gas, and
                                                   sanitary services.
                                             622  Health services.
                                             611  Educational Services.
------------------------------------------------------------------------
\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.
    WorldWide 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 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. Opacity Monitoring
    B. Additional Proposed Amendments to Subpart D
    C. Additional Proposed Amendments to Subpart Da
    D. Additional Proposed Amendments to Subpart Db and Dc
III. Rationale for Proposed Amendments
    A. Alternate Opacity Monitoring
    B. Additional Proposed Amendments to Subpart Da
    C. Additional Proposed Amendments to Subparts Db and Dc
IV. Opacity Monitoring for Facilities With PM CEMS
V. 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
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations

I. Background

    New source performance standards (NSPS) implement Clean Air Act 
(CAA) section 111(b) and are issued for categories of sources which 
have been identified as causing, or contributing significantly to, air 
pollution which may reasonably be anticipated to endanger public health 
or welfare. The primary purpose of the NSPS are to help States attain 
and maintain ambient air quality by ensuring that the best demonstrated 
emission control technologies are installed as industrial 
infrastructure is modernized. Since 1970, the NSPS have been successful 
in achieving long-term emissions reductions in numerous industries by 
assuring cost-effective controls are installed on new, reconstructed, 
and modified sources.
    CAA section 111 requires that NSPS reflect the degree of emission 
limitation achievable through application of the best system of 
emissions reductions which (taking into consideration the cost of 
achieving such emissions reductions, any non-air quality health and 
environmental impact, and energy requirements) the Administrator 
determines has been adequately demonstrated. This level of control is 
commonly referred to as best demonstrated technology (BDT). CAA section 
111(b)(1)(B) requires the EPA to periodically review and revise the 
standards of performance, as necessary, to reflect improvements in 
methods for reducing emissions.
    We promulgated amendments to the new source performance standards 
for steam generating units (40 CFR part 60, subparts D, Da, Db, and Dc) 
on June 13, 2007 (72 FR 32710). The amendments added compliance 
alternatives for owners and operators of certain affected sources, 
revised certain recordkeeping and reporting requirements, corrected 
technical and editorial errors, and updated the grammatical style of 
the four subparts to be more consistent across all four steam 
generating unit NSPS.
    A petition for reconsideration of the amendments was filed by the 
Coke Oven Environmental Task Force (COETF), and we have decided to 
grant reconsideration of the amendments to the extent specified in the 
proposed rule. The amendments proposed by this action address specific 
issues for which the petitioners requested reconsideration.
    As part of this action, we are also proposing to specify opacity 
monitoring requirements for owners/operators of affected facilities 
that are subject to an opacity limit, but are not required to use a 
continuous opacity monitor system (COMS). In addition, we are 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 of 
the previous amendments. The proposed amendments would not 
significantly change our original projections for the rule's compliance 
costs, environmental benefits, burden on industry, or the number of 
affected facilities.

[[Page 33644]]

II. Proposed Amendments

A. Opacity Monitoring

    We are proposing multiple options to monitor opacity for owners/
operators of affected facilities that are subject to an opacity limit, 
but exempt from the COMS requirement. Under the first option, the 
owner/operator conducts an annual EPA Method 9 opacity performance test 
on each affected facility to demonstrate compliance with the applicable 
opacity limit. A second option is for the owner/operator to use annual 
EPA Method 22 observations in lieu of Method 9 observations to 
demonstrate that the sum of occurrences of any visible emissions is not 
in excess of 5 percent of the observation period. As a third option, we 
are proposing the use of a digital photographic technique for detecting 
visible emissions, as an explicit alternative to Method 22 
observations. This proposed rule references an EPA preliminary method 
entitled ``Determination of Visible Emission Opacity from Stationary 
Sources Using Computer-Based Photographic Analysis Systems'' found at 
http://www.epa.gov/tnn/emc/prelim/pre-008.pdf. For this third option, 
the facility owner/operator would prepare a site-specific monitoring 
plan based on this technology for approval. Observations using either 
Method 22 or the digital photographic technique demonstrating that the 
presence of visible emissions is less than 5 percent of the observation 
period would be sufficient to demonstrate compliance with the opacity 
limit. However, if either the Method 22 observation or the digital 
photographic technique shows the presence of visible emissions in 
excess of 5 percent of the observation period, then the owner/operator 
would be required to conduct a Method 9 performance test within 24 
hours to demonstrate compliance with the opacity limit.
    We are also proposing to require owners/operators of affected 
facilities that elect to use PM CEMS to measure both the filterable and 
condensable particulate matter emissions and to take Method 9 opacity 
readings during the initial PM CEMS calibration and ongoing correlation 
testing and to electronically report those results.

B. Additional Proposed Amendments to Subpart D

    We are proposing to exempt owners/operators of affected facilities 
subject to subpart D that burn 500 part per million (ppm) or less 
sulfur distillate oil from the requirement to install a COMS.

C. Additional Proposed Amendments to Subpart Da

    We are proposing several additional amendments to subpart Da. 
First, we are proposing to exempt from the requirement to install a 
COMS owners/operators of affected facilities subject to subpart Da that 
burn 500 ppm or less sulfur distillate oil. Second, we are proposing to 
add a provision to postpone PM performance testing for owners/operators 
of affected facilities that are not operating at the time a PM 
performance test is required to be conducted. The PM performance test 
would not be required until after the affected facility recommences 
operation. Finally, we are proposing to add a provision requiring that 
owners/operators of an affected facility constructed after February 28, 
2005 with a wet scrubber for which the owner/operator elects to use the 
opacity baseline approach to monitor the performance of their primary 
PM control device, to maintain the liquid-to-gas flow rate at 90 
percent or higher of the ratio measured during the most recent PM 
performance test.

D. Additional Proposed Amendments to Subpart Db

    We are proposing several amendments to subpart Db. First, since 
synthetic natural gas derived from coal has uncontrolled emissions 
similar to those of natural gas, we are proposing that synthetic 
natural gas derived from coal be considered natural gas instead of coal 
under the rule. Similarly, since diesel fuel has emissions similar to 
distillate oil, we are proposing to include diesel fuel in the 
definition of distillate oil. Second, we are proposing to amend the 
definition of potential sulfur dioxide emission rate. This will clarify 
that owners/operators of boilers burning gasified coal and oil that has 
been desulfurized prior to combustion are able to claim credit for 
pretreatment reductions when using the fuel-based compliance 
alternatives. Third, we are proposing to amend the definition of steam 
generating unit to clarify that all water heaters, regardless of the 
mechanism used to heat the water, are covered by the NSPS. Fourth, we 
are proposing to change the definition of very low sulfur oil from 0.30 
weight percent sulfur to 0.50 weight percent sulfur for owners/
operators of affected facilities built after February 28, 2005, that 
are located in noncontinental areas. Finally, we are proposing to allow 
fuel blending to achieve the optional numerical sulfur dioxide 
(SO2) limit.
    We are proposing to make several amendments primarily impacting 
owner/operators of boilers burning coke oven gas (COG). First, we are 
proposing to align the regulatory test with the intent of the 
amendments published June 13, 2007 (72 FR 32710) and extend the 30-day 
SO2 limit maintenance exemption to owners/operators of COG-
fired boilers constructed prior to February 28, 2005 to include 
maintenance of all SO2 control technologies in the 
exemption, and to require reporting of what maintenance was performed 
during the control device outage. We are also proposing that owners/
operators of affected facilities burning gasified coal receive the same 
nitrogen oxide (NOX) monitoring options as owners/operators 
of affected facilities burning natural gas. If adopted, this amendment 
would provide owners/operators of affected facilities burning gasified 
coal the option to develop a site-specific monitoring plan as an 
alternative to using a NOX CEMS to monitor NOX 
emissions.

E. Additional Proposed Amendments to Subpart Dc

    We are proposing several amendments to subpart Dc. First, since 
synthetic natural gas derived from coal has uncontrolled emissions 
similar to those of natural gas, we are proposing that synthetic 
natural gas derived from coal be considered natural gas instead of 
coal. Similarly, since diesel fuel has emissions similar to those of 
distillate oil, we are proposing to include diesel fuel in the 
definition of distillate oil. Second, we are proposing to amend the 
definition of steam generating unit to clarify that all water heaters, 
regardless of the mechanism used to heat the water, are covered by the 
NSPS. Finally, we are proposing to allow fuel blending to achieve the 
optional numerical SO2 limit.

III. Rationale for Proposed Amendments

A. Alternate Opacity Monitoring

    The amendments to the new source performance standards for steam 
generating units promulgated on June 13, 2007 (72 FR 32710) eliminated 
the requirement to install and properly operate a COMS, but not the 
opacity standard, for owners/operators of certain affected facilities. 
Those affected facilities include any steam generating unit using a PM 
CEMS to demonstrate compliance with the applicable PM limit, oil-fired 
steam generating units with a carbon monoxide CEMS, steam generating 
units firing 500 ppm sulfur distillate oil or less (subparts Db and Dc 
only), and owners/operators monitoring

[[Page 33645]]

opacity emissions under a site-specific plan approved by the permitting 
authority (subparts Db and Dc only). We intended in promulgating the 
previous amendments to provide the COMS exemption to owners/operators 
of steam generating units firing 500 ppm sulfur distillate oil or less 
across all of the subparts. However, we only added the regulatory 
language to subparts Db and Dc. The proposed amendments will implement 
the intent of the previous rulemaking by adding the language to 
subparts D and Da.
    The previous amendments did not specify the type and frequency of 
alternate opacity monitoring for affected facilities that do not 
demonstrate compliance with the opacity limit using a COMS. Without 
adding specific requirements, it would be up to the permitting 
authority to determine the proper level of monitoring. Since the COMS 
exemption is only available to owner/operators of facilities 
continuously monitoring parameters indicative of opacity (i.e., oil-
fired facilities with CO CEMS) or burning fuels with inherently low 
opacity (i.e., 500 ppm sulfur distillate oil-fired facilities), we are 
proposing to require opacity observations be done only every 12 months. 
However, this does not prevent the permitting authority, or any 
qualified individual, from performing Method 9 observation at any time 
to determine excess opacity. While Method 9 remains the most reliable 
means of determining compliance with an applicable opacity limit, we 
are including Method 22 as an alternative to Method 9 since it requires 
an observer, but not necessarily a certified Method 9 observer. This 
option is likely to lower the compliance burden, since an uncertified 
observer is able to monitor the affected facility for any visible 
emissions (i.e., not zero). For sources with multiple stacks, the use 
of a digital camera system would also reduce compliance costs, while 
still providing equivalent protection for the environment.
    Due to the potential emissions from steam generating units, 
especially utility size facilities, we are specifically requesting 
comment on whether the frequency of the opacity observations should be 
increased and are considering two alternatives for the final rule. The 
first would increase the frequency of performance testing and require 
that Method 9 performance tests be completed once each calendar month 
or once each calendar quarter. The second alternate approach we are 
considering would require the owner/operator to perform either daily or 
weekly Method 22 (or digital photographic technique) brief observations 
(i.e., 5 to 15 minutes). If any visible emissions are detected, the 
owner/operator would be required to conduct a longer (i.e., at least 1 
hour) observation to determine if the sum of the time visible emissions 
are present is less than 5 percent of the observation period. If the 
visible emissions are in excess of 5 percent of the observation period, 
then a Method 9 performance test would be required within 24 hours. The 
benefit of the frequent, but brief, Method 22 approach is that it 
provides more assurance than the once a year approach that the facility 
is operating properly, but it still keeps the compliance burden 
relatively low.

B. Additional Proposed Amendments to Subpart Da

    We are proposing to delay the required PM performance test for 
facilities that are not operating at the time such a test is otherwise 
required because we have concluded that it is not beneficial to the 
environment or appropriate to require a facility to operate just to 
conduct a performance test. Also, in the June 13, 2007 rulemaking (72 
FR 32710), we intended to include the requirement that owners/operators 
of an affected facility constructed after February 28, 2005 that 
employs a wet scrubber who choose to use a baseline opacity level to 
monitor PM control device performance maintain the liquid to gas ratio 
of the scrubber that was used during the most recent performance test. 
Since scrubbers can potentially impact PM emissions, we have concluded 
that it is necessary that the liquid to gas ratio be maintained at the 
same or higher level as during the performance test as part of the 
requirement to demonstrate continuous compliance with the PM limit. 
This provision is presently included in the requirements for owners/
operators using a predictive electrostatic precipitator (ESP) model to 
monitor PM control device performance, and the proposed amendments 
update the regulatory text to reflect the intent of the original 
rulemaking.

C. Additional Proposed Amendments to Subparts Db and Dc

    The intent of the alternate numerical SO2 limit of 0.20 
lb SO2/MMBtu added in the amendments published on February 
27, 2006 (71 FR 9866) was to provide flexibility to owners/operators of 
steam generating units burning fuels with inherently low sulfur 
contents. We are proposing to clarify that fuel blending with low 
sulfur fuels (i.e. natural gas) can be done to achieve the optional 
numerical SO2 limit. The use of fuel blending decreases 
compliance costs for facilities. If a facility gets a single delivery 
of fuel with higher than expected sulfur content, the facility owner/
operator can blend in low sulfur fuels to achieve the standard.
    The proposal also clarifies that the term steam generating unit 
includes units which heat water regardless of whether the water is 
heated directly, indirectly, or as a heat transfer medium. The 
preambles to the final subpart Db rulemakings (November 25, 1986, 51 FR 
42768 and 42772) and December 16, 1987 (52 FR 47826) were clear about 
our intent to include facilities which produce hot water without 
subsequently converting the water to steam in the definition of steam 
generating unit. Because there continues to be questions as to whether 
the definition of steam generating unit includes direct contact water 
heaters, we are taking this opportunity to confirm that ``steam 
generating unit'' includes any unit that combusts fuel and heats water, 
and does not categorically exclude direct contact water heaters. This 
clarification is not meant to reverse source-specific applicability 
determinations that were issued prior to today. We are also reaffirming 
that fuel combustion units which function as process heaters are not 
covered as steam generating units if their primary purpose is to heat a 
fluid in order to initiate or promote a chemical reaction in which the 
fluid itself is a reactant or catalyst. The heating of water to act as 
a heat transfer medium for vaporizing liquid natural gas, for example, 
would not generally meet the definition of a process heater.
    The proposed amendments addressing steam generating units located 
in noncontinental areas that burn distillate oil or residual oil is 
based on the fact that oil containing 0.30 weight percent or less 
sulfur is not always readily available to owners/operators of such 
units, but that 0.50 weight percent sulfur distillate oil and residual 
oil are generally available. It was not the intent of the amendments 
published on February 27, 2006 (71 FR 9866) to require owners/operators 
of oil-fired steam generating units located in noncontinental areas to 
incur high fuel transportation costs or to install post combustion 
controls on oil-fired boilers. The proposed amendments to the 
definition of very low sulfur oil and the corresponding low sulfur oil 
PM exemption and SO2 limit exemptions would allow owner/
operators of oil-fired steam generating units located in noncontinental 
areas to demonstrate compliance with both limits using fuel receipts.
    We are proposing that gasified coal (including COG) have the same 
NOX

[[Page 33646]]

monitoring option as natural gas, distillate oil, and low nitrogen 
content residual oil since gasified coal has uncontrolled 
NOX emissions similar to those of natural gas. Even though 
COG is a byproduct gas and not generated for the purposes of creating 
useful heat, it is considered coal for the purposes of subpart Db. In 
addition, even though the chemical compositions of COG and gasified 
coal that is generated for the purposes of creating useful heat are 
different, both have similar uncontrolled NOX emission 
rates.
    Because of the specific characteristics of the steel industry, the 
current regulations allow a 30-day exceedance per year from the 
SO2 emission limit for steam generating units constructed 
after February 28, 2005 that burn COG exclusively or in combination 
with other gaseous fuels or distillate oil. COG desulfurization 
facilities regardless of when the steam generating units they serve 
were constructed 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 
increased NOX emissions without achieving any reductions in 
SO2. We are, therefore, proposing to expand this exemption 
to owners/operators of COG-fired boilers constructed prior to February 
28, 2005 and to the use of post-combustion controls since both pre- and 
post-combustion controls require maintenance. We are also proposing to 
add a reporting requirement to assure that any SO2 
exceedances are due to valid maintenance periods.

IV. Opacity Monitoring for Facilities With PM CEMS

    There are several conditions that result in opacity from steam 
generating units. These include emissions of PM, NOX, and 
reactions of stack gases in the atmosphere. However, opacity from 
NOX emissions is rare and only occurs at high NOX 
emissions rates. All modern steam generating units have inherent 
NOX emissions rates below the level that would result in 
opacity emissions. Therefore, for modern steam generating units, the 
primary causes of opacity are PM and reactions of stack gases that 
occur after the gases are discharged to the atmosphere. PM CEMS detect 
solid or liquid PM at the stack conditions, and COMS detect anything 
that blocks light at the stack conditions. Since PM CEMS measure 
filterable PM (PM that is either in a solid or liquid state at the 
stack conditions) and COMS measure opaque material that can be used as 
a surrogate for particulate matter, we concluded in a previous 
rulemaking (71 FR 9866) that it is appropriate for owners/operators of 
affected facilities who use a PM CEMS (to demonstrate compliance with 
the applicable PM limit) to eliminate the use of COMS. However, the 
opacity standard itself was not eliminated, and owners/operators of 
facilities who elect not to install PM CEMS are required to continue to 
use COMS. Furthermore, it is possible that an owner/operator of an 
affected facility could be in compliance with the opacity limit in the 
stack (i.e., COMS measurements), but that a Method 9 observation could 
detect plume opacity violations.
    Since opacity data has been used as a surrogate for PM emissions 
\1\ and since PM CEMS give a more direct continuous measurement of the 
primary pollutant of interest causing opacity at steam generating units 
and provides data in units of the PM standard, we are requesting 
comment on if eliminating the opacity standard altogether for owner/
operators using PM CEMS would be appropriate. However, neither a COMS 
nor a PM CEMS \2\ detects condensable PM (i.e., PM that is in the 
gaseous state at the stack conditions but that will condense to form 
solid or liquid particulate matter at atmospheric conditions). 
Therefore, if we were to adopt this option and eliminate the opacity 
requirement for affected facilities with PM CEMS, we are proposing to 
require owners/operators of an affected facility with a PM CEMS to 
measure and electronically report filterable and condensable PM along 
with Method 9 opacity data (Method 9 observations of the plume opacity 
may detect the presence of condensable PM) during the initial and 
ongoing calibration of the PM CEMS. With sufficient data, we will be 
able to determine if a relationship exists between filterable and 
condensable PM and opacity and to establish direct or parametric 
monitoring approaches for condensable PM, including those relying on 
techniques other than opacity, and an appropriate condensable PM limit.
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    \1\ Opacity is also used as an indicator of control device 
operation and proper maintenance.
    \2\ New PM CEMS are being developed that may measure condensable 
PM.
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V. 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 will not change the costs or benefits of the rule. 
However, EPA is requesting additional comments on the issue.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden. 
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 OMB during the 
development of the existing standards of performance. Therefore, the 
information collection requests have not been amended. However, OMB has 
previously approved the information collection requirements contained 
in the existing regulations (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 
for 40 CFR part 60, subpart Da, 2060-0072 for 40 CFR part 60, subpart 
Db, and 2060-0202 for 40 CFR part 60, subpart Dc. The OMB control 
numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act 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 this rule on small 
entities, small entity is defined as: (1) A small business as defined 
by the Small Business Administration's regulations at 13 CFR

[[Page 33647]]

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. This 
proposed rule will not impose any requirements on small entities.
    We continue to be interested in the potential impacts of the 
proposed rule on small entities and welcome comments on issues related 
to such impacts.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
one year. Before promulgating an EPA rule for which a written statement 
is needed, section 205 of the UMRA generally requires EPA to identify 
and consider a reasonable number of regulatory alternatives and adopt 
the least costly, most cost-effective or least burdensome alternative 
that achieves the objectives of the rule. The provisions of section 205 
do not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows EPA to adopt an alternative other than the least 
costly, most cost effective or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before EPA establishes any regulatory 
requirements that may significantly or uniquely affect small 
governments, including tribal governments, it must have developed under 
section 203 of the UMRA a small government agency plan. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of EPA regulatory proposals with significant 
Federal intergovernmental mandates, and informing, educating, and 
advising small governments on compliance with the regulatory 
requirements.
    EPA has determined that this rule does not contain a Federal 
mandate that may result in expenditures of $100 million or more for 
State, local, and tribal governments, in the aggregate, or the private 
sector in any one year. Thus, this rule is not subject to the 
requirements of section 202 and 205 of the UMRA. In addition, EPA 
determined that this rule contains 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, this rule is not subject to the requirements of 
section 203 of the UMRA.

E. Executive Order 13132: Federalism

    Executive Order (EO) 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 EO 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.''
    This proposed rule does not have federalism implications. It 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 EO 13132. These proposed amendments will not impose 
substantial direct compliance costs on State or local governments; they 
will not preempt State law. Thus, EO 13132 does not apply to this rule. 
In the spirit of EO 13132, and consistent with EPA policy to promote 
communications between EPA and State and local governments, EPA 
specifically solicits comment on this proposed rule from State and 
local officials.

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.'' This proposed rule does not 
have tribal implications, as specified in EO 13175. Thus, EO 13175 does 
not apply to this rule. EPA specifically solicits additional comment on 
this proposed rule from tribal officials.

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

    EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying 
to those regulatory actions that concern health or safety risks, such 
that the analysis required under section 5-501 of the EO has the 
potential to influence the regulation. This proposed rule is not 
subject to EO 13045 because it is based solely on technology 
performance.

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

    This rule 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 No. 104-113 (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards (VCS) in its 
regulatory activities unless to do so would be inconsistent with 
applicable law or otherwise impractical. Voluntary consensus standards 
are technical standards (e.g., materials specifications, test methods, 
sampling procedures, and business practices) that are developed or 
adopted by voluntary consensus standards bodies. NTTAA directs EPA to 
provide Congress, through OMB, explanations when the Agency decides not 
to use available and applicable voluntary consensus standards.
    This proposed rulemaking involves technical standards. EPA proposes 
to use ASTM D975-08, ``Standard Specification for Diesel Fuel Oils,'' 
for defining diesel fuel oil. This standard is available from the 
American Society for Testing and Materials (ASTM), 100 Barr Harbor 
Drive, Post Office Box C700, West Conshohocken, PA 19428-2959.
    The EPA has also decided to use EPA Method 202 (40 CFR part 51, 
appendix M). The Agency has not found any alternative methods. The 
search and review results are in the docket for this regulation.

[[Page 33648]]

    Under 40 CFR 60.13(i) of the NSPS General Provisions, a source may 
apply to EPA for permission to use alternative test methods or 
alternative monitoring requirements in place of any required testing 
methods, performance specifications, or procedures in the final rule 
and amendments. EPA welcomes comments on this aspect of the proposed 
rulemaking and, specifically, invites the public to identify 
potentially-applicable voluntary consensus standards and to explain why 
such standards should be used in this proposed action.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes 
Federal executive policy on environmental justice. Its main provision 
directs Federal agencies, to the greatest extent practical and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    EPA has determined that this proposed rule will not have 
disproportionately high adverse human health or environmental effects 
on minority or low-income populations because it increases the level of 
environmental protection for all affected populations without having 
any disproportionately high adverse human health or environmental 
effects on any populations, including any minority or low-income 
population.

List of Subjects in 40 CFR Part 60

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

    Dated: May 30, 2008.
Stephen L. Johnson,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part 
60, of the Code of the Federal Regulations is proposed to be amended as 
follows:

PART 60--[AMENDED]

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

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

Subpart A--[Amended]

    2. Section 60.17 is amended by redesignating paragraphs (a)(17) 
through (a)(92) as paragraphs (a)(18) through (a)(93) and by adding new 
paragraph (a)(17) to read as follows:


Sec.  60.17  Incorporations by Reference.

* * * * *
    (17) ASTM D975-08, Standard Specification for Diesel Fuel Oils, IBR 
approved for Sec. Sec.  60.41(b) of subpart Db of this part and 60.41c 
of subpart Dc of this part.
* * * * *

Subpart D--[Amended]

    3. Section 60.43 is amended by revising paragraph (d) to read as 
follows:


Sec.  60.43  Standard for sulfur dioxide (SO2).

* * * * *
    (d) As an alternate to meeting the requirements of 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 or comply with Sec.  60.42b(k)(4) of subpart Db 
of this part, as applicable to the affected source. 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 
or Sec.  60.42b(k)(4) of subpart Db of this part, as applicable to the 
affected source.
* * * * *
    4. Section 60.45 is amended to read as follows:
    a. By revising paragraph (b)(1) and adding new paragraph (b)(7); 
and
    b. By revising paragraphs (g)(2),(g)(3), and (g)(4).


Sec.  60.45  Emissions and fuel monitoring.

* * * * *
    (b) * * *
    (1) For a fossil-fuel-fired steam generator that burns only gaseous 
or liquid fossil fuel (excluding residual oil) with potential 
SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less 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 if the owner or operator 
monitors SO2 emissions by fuel sampling and analysis or fuel 
receipts.
* * * * *
    (7) The owner or operator of an affected facility subject to an 
opacity standard under Sec.  60.42 and that elects to not install a 
CEMS for measuring opacity because the affected facility burns only 
fuels as specified under paragraph (b)(1) of this section, monitors PM 
emissions as specified under paragraph (b)(5) of this section, or 
monitors CO emissions as specified under paragraph (b)(6) of this 
section shall comply with either paragraphs (b)(7)(i), (b)(7)(ii), or 
(b)(7)(iii) of this section.
    (i) Conduct a performance test using Method 9 of Appendix A-4 of 
this part and the procedures in Sec.  60.11 to demonstrate compliance 
with the applicable limit in Sec.  60.42. The Method 9 observations 
must be completed, at a minimum, every 12 months; or
    (ii) Conduct a series of three 1-hour observations (during normal 
operation) using Method 22 of Appendix A-7 of this part at the affected 
facility and demonstrate that the sum of the occurrences of any visible 
emissions is not in excess of 5 percent of the observation period 
(i.e., 9 minutes per 3-hour period). The Method 22 observations must be 
completed, at a minimum, every 12 months. If the sum of the occurrences 
of visible emissions in excess of 5 percent of the observation period, 
then the owner or operator shall conduct a performance test within 24 
hours according to the requirements in Sec.  60.46(a)(3); or
    (iii) Monitor opacity using a digital opacity compliance system 
according to a site-specific monitoring plan approved by the 
Administrator. The observations should include at least one digital 
image every 15 seconds for three separate 1-hour periods (during normal 
operation) every 12 months. An approvable monitoring plan should 
include a demonstration that the occurrences of visible emissions are 
not in excess of 5 percent of the observation period (i.e., 36 
observations per 3-hour period). For reference purposes in preparing 
the monitoring plan, see OAQPS ``Determination of Visible Emission 
Opacity from Stationary Sources Using Computer-Based Photographic 
Analysis Systems.'' This document is available from the U.S. 
Environmental Protection Agency (U.S. EPA); Office of Air Quality and 
Planning 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 Preliminary Methods. If the sum of the 
occurrences of any visible emissions is in excess of 5 percent of the 
observation period, then the owner or operator shall conduct a new 
performance test within

[[Page 33649]]

24 hours according to the requirements in Sec.  60.46(a)(3).
* * * * *
    (g) * * *
    (2) Sulfur dioxide. Excess emissions for affected facilities are 
defined as:
    (i) For affected facilities electing not to comply with Sec.  
60.43(d), 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) For affected facilities electing to comply with Sec.  
60.43(d), 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 or Sec. Sec.  60.45b and 
60.47b of subpart Db of this part, as applicable.
    (3) Nitrogen oxides. Excess emissions for affected facilities using 
a CEMS for measuring NOX are defined as:
    (i) For affected facilities electing not to comply with Sec.  
60.44(e), 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) For affected facilities electing to comply with Sec.  
60.44(e), 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.  60.44. 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.  
60.42. 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.
    5. Section 60.46 is amended by revising paragraph (b)(2) 
introductory text to read as follows:


Sec.  60.46  Test methods and procedures.

* * * * *
    (b) * * *
    (2) Method 5 of appendix A-3 of this part shall be used to 
determine PM concentration (C) at affected facilities without wet flue-
gas-desulfurization (FGD) systems and Method 5B of appendix A-3 of this 
part shall be used to determine the PM concentration (C) after FGD 
systems. Method 5 or 5B of appendix A-3 of this part, Method 17 of 
appendix A-6 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-3 of this 
part may be used with Method 17 of appendix A-6 of this part only if it 
is used after wet FGD systems. Method 17 of appendix A-6 of this part 
shall not be used after wet FGD systems if the effluent gas is 
saturated or laden with water droplets.
* * * * *

Subpart Da--[Amended]

    6. Section 60.40Da is amended by revising paragraph (b)(4) to read 
as follows:


Sec.  60.40Da  Applicability and designation of affected facility.

* * * * *
    (b) * * *
    (4) Heat recovery steam generators that are associated with 
combined cycle gas turbines that meet the applicability requirements of 
subpart KKKK of this part are not subject to this part. This subpart 
will continue to apply to all other electric utility combined cycle gas 
turbines that are capable of combusting more than 73 MW (250 MMBtu/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).
* * * * *
    7. Section 60.41Da is amended in paragraph (c) by revising the 
definitions of ``Gross output,'' ``Petroleum,'' and ``Potential 
combustion concentration'' to read as follows:


Sec.  60.41Da  Definitions.

* * * * *
    (c) * * *
    Gross output means the gross useful work performed by the steam 
generated and, for an IGCC electric utility steam generating unit, the 
work performed by the stationary combustion turbines. For a unit 
generating only electricity, the gross useful work performed is the 
gross electrical output from the unit's turbine/generator sets. For a 
cogeneration unit, 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 or to enhance the 
performance of the unit (i.e., steam delivered to an industrial 
process).
* * * * *
    Petroleum means crude oil or a fuel derived from crude oil, 
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:
* * * * *
    8. Section 60.48Da is amended to read as follows:
    a. By revising paragraph (n);
    b. By revising paragraphs (o) introductory text, (o)(1), (o)(2)(ii) 
introductory text, (o)(2)(iii), (o)(2)(iv), (o)(2)(vi), (o)(3)(i), 
(o)(3)(iii), and (o)(5); and
    c. By adding paragraph (q).


Sec.  60.48Da  Compliance provisions.

* * * * *
    (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) or Sec.  
60.49Da(m)), 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 and Sec.  60.49Da(a)(2), 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

[[Page 33650]]

according to the requirements in paragraphs (o)(1) through (o)(5) of 
this section.
    (1) You must conduct a performance test to demonstrate initial 
compliance with the applicable PM emissions limit in Sec.  
60.42Da(c)(2) or (d) by the applicable date specified in Sec.  60.8(a). 
Thereafter, you must conduct each subsequent performance test within 12 
calendar months following the date the previous performance test was 
required to be conducted. You must conduct each performance test 
according to the requirements in Sec.  60.8 using the test methods and 
procedures in Sec.  60.50Da. An affected facility that has not operated 
for 2 months prior to the due date of a performance test is not 
required to perform the subsequent performance test until 60 days after 
the next boiler operating day.
    (2) * * *
    (ii) You must comply with the quality assurance requirements in 
paragraphs (o)(2)(ii)(A) through (E) of this section.
* * * * *
    (iii) During each performance test conducted according to paragraph 
(o)(1) of this section, you must establish an opacity baseline level. 
The value of the opacity baseline level is determined by averaging all 
of the 6-minute average opacity values (reported to the nearest 0.1 
percent opacity) from the COMS measurements recorded during each of the 
test run intervals conducted for the performance test, and then adding 
2.5 percent opacity to your calculated average opacity value for all of 
the test runs. If your opacity baseline level is less than 5.0 percent, 
then the opacity baseline level is set at 5.0 percent.
    (iv) You must evaluate the preceding 24-hour average opacity level 
measured by the COMS each boiler operating day excluding periods of 
affected facility startup, shutdown, or malfunction. If the measured 
24-hour average opacity emission level is greater than the baseline 
opacity level determined in paragraph (o)(2)(iii) of this section, you 
must initiate investigation of the relevant equipment and control 
systems within 24 hours of the first discovery of the high opacity 
incident and take the appropriate corrective action as soon as 
practicable to adjust control settings or repair equipment to reduce 
the measured 24-hour average opacity to a level below the baseline 
opacity level. In cases when a wet scrubber is used alone or in 
combination with another PM control device to comply with the PM 
emissions limit, the daily average liquid-to-gas flow rate for the wet 
scrubber must be maintained at least at 90 percent of average ratio 
measured during all test run intervals for the performance test 
conducted according to paragraph (o)(1) of this section.
* * * * *
    (vi) If the measured 24-hour average opacity for your affected 
facility remains at a level greater than the opacity baseline level 
after 7 boiler operating days, then you must conduct a new PM 
performance test according to paragraph (o)(1) of this section and 
establish a new opacity baseline value according to paragraph (o)(2) of 
this section. This new performance test must be conducted within 60 
days of the date that the measured 24-hour average opacity was first 
determined to exceed the baseline opacity level unless a waiver is 
granted by the permitting authority.
    (3) * * *
    (i) You must calibrate the ESP predictive model with each PM 
control device used to comply with the applicable PM emissions limit in 
Sec.  60.42Da(c)(2) or (d) operating under normal conditions. In cases 
when a wet scrubber is used in combination with an ESP to comply with 
the PM emissions limit, the daily average liquid-to-gas flow rate for 
the wet scrubber must be maintained at least at 90 percent of average 
ratio measured during all test run intervals for the performance test 
conducted according to paragraph (o)(1) of this section.
* * * * *
    (iii) You must run the ESP predictive model using the applicable 
input data each boiler operating day and evaluate the model output for 
the preceding boiler operating day excluding periods of affected 
facility startup, shutdown, or malfunction. If the values for one or 
more of the model parameters exceed the applicable baseline levels 
determined according to your approved site-specific monitoring plan, 
you must initiate investigation of the relevant equipment and control 
systems within 24 hours of the first discovery of a model parameter 
deviation and, take the appropriate corrective action as soon as 
practicable to adjust control settings or repair equipment to return 
the model output to within the applicable baseline levels.
* * * * *
    (5) An owner or operator of a modified affected facility 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.
* * * * *
    (q) Compliance provisions for sources subject to Sec.  60.42Da(b). 
An owner or operator of an affected facility subject to the opacity 
standard under Sec.  60.42Da(b) shall meet the requirements in 
paragraphs (q)(1) and (2) of this section.
    (1) Demonstrate compliance of the affected facility with the 
opacity limit in Sec.  60.42Da(b) initially and, thereafter, except as 
provided in paragraphs Sec.  60.49Da(a)(3)(ii) and (iii), at least once 
every 12 months according to the requirements in Sec.  60.50Da(b)(3), 
and
    (2) Monitor the opacity of emissions discharged from the affected 
facility to the atmosphere according to the requirements in Sec.  
60.49Da(a), as applicable to the affected facility.
    9. Section 60.49Da is amended to read as follows:
    a. By revising paragraph (a);
    b. By revising paragraph (t);
    c. By revising paragraph (u);
    d. By revising paragraph (v); and
    e. By revising paragraph (w)(2).


Sec.  60.49Da  Emission monitoring.

    (a) An owner or operator of an affected facility subject to the 
opacity standard under Sec.  60.42Da(b) shall monitor the opacity of 
emissions discharged from the affected facility to the atmosphere 
according to the applicable requirements in paragraphs (a)(1) through 
(3) of this section.
    (1) Except as provided for in paragraph (a)(2) 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 (i.e., 
install, calibrate, maintain, and operate a COMS). 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).
    (2) An owner or operator of an affected facility that meets the 
conditions in either paragraph (a)(2)(i), (ii), or (iii) of this 
section may elect to comply with the requirements of paragraph (a)(3) 
of this section as an alternative to the monitoring

[[Page 33651]]

requirements in paragraph (a)(1) of this section.
    (i) The affected facility uses a CEMS for measuring PM emissions to 
demonstrate continuous compliance on a boiler operating day average 
with the emissions limitations under Sec. Sec.  60.42Da(a)(1), 
60.42Da(c)(1), or 60.42Da(c)(2), and the PM CEMS is installed, 
certified, operated, and maintained on the affected facility according 
to the requirements of paragraph (v) of this section; or
    (ii) The affected facility burns only gaseous or liquid fuels 
(excluding residual oil) 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 emissions of SO2 or PM; or
    (iii) The affected facility does not use post-combustion technology 
(except a wet scrubber) for reducing PM, SO2, or carbon 
monoxide (CO) emissions, burns only natural gas, gaseous fuels, or fuel 
oils that contain less than or equal to 0.30 weight percent sulfur, and 
is operated such that emissions of CO to the atmosphere from the 
affected facility are maintained at levels less than or equal to 1.4 
lb/MWh on a boiler operating day average basis. Owners and operators of 
affected facilities electing to comply with this paragraph must use a 
CEMS measuring CO emissions and demonstrate compliance according to the 
procedures specified in paragraph (u) of this section.
    (3) The owner or operator of an affected facility that meets the 
conditions in paragraph (a)(2) of this section shall monitor the 
opacity of emissions discharged from the affected facility to the 
atmosphere according to the requirements in either paragraph (a)(3)(i), 
(ii), or (iii) of this section,
    (i) Conduct a performance test using Method 9 of appendix A-4 of 
this part and the procedures in Sec.  60.11 to demonstrate compliance 
with the limit in Sec.  60.42Da(b). The Method 9 observations must be 
completed, at a minimum, every 12 months; or
    (ii) Conduct a series of three 1-hour observations (during normal 
operation) using Method 22 of appendix A-7 of this part at the affected 
facility and demonstrate that the sum of the occurrences of any visible 
emissions is not in excess of 5 percent of the observation period 
(i.e., 9 minutes per 3-hour period). The Method 22 observations must be 
completed, at a minimum, every 12 months. If the sum of the occurrences 
of any visible emissions is in excess of 5 percent of the observation 
period, then the owner or operator shall conduct a new performance test 
within 24 hours according to the requirements in Sec.  60.50Da(b)(3); 
or
    (iii) Monitor opacity using a digital opacity compliance system 
according to a site-specific monitoring plan approved by the 
Administrator. The observations should include at least one digital 
image every 15 seconds for three separate 1-hour periods (during normal 
operation) every 12 months. An approvable monitoring plan should 
include a demonstration that the occurrences of visible emissions are 
not in excess of 5 percent of the observation period (i.e., 36 
observations per 3-hour period). For reference purposes in preparing 
the monitoring plan, see OAQPS ``Determination of Visible Emission 
Opacity from Stationary Sources Using Computer-Based Photographic 
Analysis Systems.'' This document is available from the U.S. 
Environmental Protection Agency (U.S. EPA); Office of Air Quality and 
Planning 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 Preliminary Methods. If the sum of the 
occurrences of any visible emissions is in excess of 5 percent of the 
observation period, then the owner or operator shall conduct a new 
performance test within 24 hours according to the requirements in Sec.  
60.50Da(b)(3).
* * * * *
    (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 facility 
demonstrating compliance with the input-based emission limitation under 
Sec.  60.42Da(a)(1) or 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) The owner or operator of an affected facility using a CEMS 
measuring CO emissions to meet requirements of this subpart shall meet 
the requirements specified in paragraphs (u)(1) through (4) of this 
section.
    (1) You must monitor CO emissions using a CEMS according to the 
procedures specified in paragraphs (u)(1)(i) through (iv) of this 
section.
    (i) The CO CEMS must be installed, certified, maintained, and 
operated according to the provisions in Sec.  60.58b(i)(3) of subpart 
Eb of this part.
    (ii) Each 1-hour CO emissions average is calculated using the data 
points generated by the CO CEMS expressed in parts per million by 
volume corrected to 3 percent oxygen (dry basis).
    (iii) At a minimum, valid 1-hour CO emissions averages must be 
obtained for at least 90 percent of the operating hours on a 30-day 
rolling average basis. At least two data points per hour must be used 
to calculate each 1-hour average.
    (iv) Quarterly accuracy determinations and daily calibration drift 
tests for the CO CEMS must be performed in accordance with procedure 1 
in appendix F of this part.
    (2) You must calculate the 1-hour average CO emissions levels for 
each boiler operating day by multiplying the average hourly CO output 
concentration measured by the CO CEMS times the corresponding average 
hourly flue gas flow rate and divided by the corresponding average 
hourly useful energy output from the affected facility. The 24-hour 
average CO emission level is determined by calculating the arithmetic 
average of the hourly CO emission levels computed for each boiler 
operating day.
    (3) You must evaluate the preceding 24-hour average CO emission 
level each boiler operating day excluding periods of affected facility 
startup, shutdown, or malfunction. If the 24-hour average CO emission 
level is greater than 1.4 lb/MWh, you must initiate investigation of 
the relevant equipment and control systems within 24 hours of the first 
discovery of the high emission incident and, take the appropriate 
corrective action as soon as practicable to adjust control settings or 
repair equipment to reduce the 24-hour average CO emission level to 1.4 
lb/MWh or less.
    (4) You must record the CO measurements and calculations performed 
according to paragraph (u)(3) of this section and any corrective 
actions taken. The record of corrective action taken must include the 
date and time during which the 24-hour average CO emission level was 
greater than 1.4 lb/MWh, and the date, time, and description of the 
corrective action.
    (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)(4) of this section.
    (1) The owner or operator shall conduct a performance evaluation of 
the CEMS according to the applicable requirements of Sec.  60.13, 
Performance

[[Page 33652]]

Specification 11 in appendix B of this part, and procedure 2 in 
appendix F of this part.
    (2) During each PM correlation testing 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, Method 5 or 5B of appendix A-3 of this part or Method 
17 of appendix A-6 of this part shall be used; and
    (ii) For condensable PM emissions, Method 202 of appendix M of part 
51 shall be used; and
    (iii) For visible emissions, Method 9 of Appendix A-4 shall be 
used; and
    (iv) For O2 (or CO2), Method 3, 3A, or 3B of appendix A-2 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.
    (4) Within 90 days after the date of completing each performance 
evaluation required by paragraph (v) of this section, the owner or 
operator of the affected facility must submit the test data to EPA by 
successfully entering the data electronically into EPA's WebFire data 
base available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. If the owner or operator is unsuccessful in 
entering the test data into EPA's WebFire data base, then the owner or 
operator must submit monthly reports to EPA until the data is 
successfully submitted to WebFire. The monthly reports shall describe 
the difficulty preventing successful submittal of the data and what 
actions are being taken to correct the problem.
    (w) * * *
    (2) As an alternative to meeting the requirements of paragraph 
(w)(1) of this section, an owner or operator may elect to implement the 
following alternative data accuracy assessment procedures. For all 
required CO2 and O2 CEMS and for SO2 and NOX CEMS with span values 
greater than or equal to 100 ppm, the daily calibration error test and 
calibration adjustment procedures described in sections 2.1.1 and 2.1.3 
of appendix B to part 75 of this chapter may be followed instead of the 
CD assessment procedures in Procedure 1, section 4.1 of appendix F of 
this part. If this option is selected, the data validation and out-of-
control provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75 
of this chapter shall be followed instead of the excessive CD and out-
of-control criteria in Procedure 1, section 4.3 of appendix F to this 
part. For the purposes of data validation under this subpart, the 
excessive CD and out-of-control criteria in Procedure 1, section 4.3 of 
appendix F to this part shall apply to SO2 and NOX span values less 
than 100 ppm;
* * * * *
    10. Section 60.50Da is amended by revising paragraph (f) to read as 
follows:


Sec.  60.50Da  Compliance determination procedures and methods.

* * * * *
    (f) Electric utility combined cycle gas turbines that are not 
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 are performance tested for PM, SO2, 
and NOX using the procedures of Method 19 of appendix A-7 of this part. 
The SO2 and NOX emission rates from the gas turbine used in the Method 
19 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.
* * * * *

Subpart Db--[Amended]

    11. Section 60.40b is amended by revising paragraph (i) to read as 
follows:


Sec.  60.40b  Applicability and delegation of authority.

* * * * *
    (i) Heat recovery steam generators that are associated with 
combined cycle gas turbines and that meet the applicability 
requirements of subpart KKKK of this part are not subject to this 
subpart. This subpart will continue to apply to all other heat recovery 
steam generators that are capable of combusting more than 29 MW (100 
MMBtu/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.)
* * * * *
    12. Section 60.41b is amended in paragraph by revising the 
definitions of ``Coal,'' ``Distillate oil,'' ``Gaseous fuel,'' ``Gross 
output,'' ``Natural gas,'' ``Potential sulfur dioxide emission rate,'' 
``Pulverized coal-fired steam generating unit,'' ``Steam generating 
unit,'' and ``Very low sulfur oil'' to read as follows:


Sec.  60.41b  Definitions.

* * * * *
    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 not 
meeting the definition of natural gas, coal-oil mixtures, coke oven 
gas, and coal-water mixtures, are also included in this definition for 
the purposes of this subpart.
* * * * *
    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) or 
diesel fuel oil as defined by the American Society for Testing and 
Materials in ASTM D975 (incorporated by reference, see Sec.  60.17).
* * * * *
    Gaseous fuel means any fuel that is present as a gas at ISO 
conditions. This includes, but is not limited to, natural gas and 
gasified coal (including coke oven gas).
    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 or to enhance 
the performance of the unit (i.e., steam delivered to an industrial 
process).
* * * * *
    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); 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 dry standard cubic

[[Page 33653]]

meter (910 and 1,150 Btu per dry standard cubic foot).
* * * * *
    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. For gasified coal or oil that is 
desulfurized prior to combustion, the Potential sulfur dioxide emission 
rate is the theoretical SO2 emissions (ng/J or lb/MMBtu heat input) 
that would result from combusting fuel in a cleaned state without using 
any post combustion emission control systems.
* * * * *
    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.
* * * * *
    Steam generating unit means a device that combusts any fuel or 
byproduct/waste and produces steam or heats water or heats any 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.
* * * * *
    Very low sulfur oil means for units constructed, reconstructed, or 
modified on or before February 28, 2005, an oil that contains no more 
than 0.50 weight percent sulfur or that, when combusted without SO2 
emission control, has a SO2 emission rate equal to or less than 215 ng/
J (0.50 lb/MMBtu) heat input. For units constructed, reconstructed, or 
modified after February 28, 2005 and not located in a noncontinental 
area, very low sulfur oil means an oil that contains no more than 0.30 
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. For units constructed, reconstructed, or modified 
after February 28, 2005 and located in a noncontinental area, very low 
sulfur oil means an oil that contains no more than 0.50 weight percent 
sulfur or that, when combusted without SO2 emission control, has a SO2 
emission rate equal to or less than 215 ng/J (0.50 lb/MMBtu) heat 
input.
* * * * *
    13. Section 60.42b is amended to read as follows:
    a. By revising paragraph (a);
    b. By revising paragraph (b);
    c. By revising paragraph (c);
    d. By revising paragraph (d) introductory text; and
    e. By revising paragraphs (k)(1), (2), and (3).


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

    (a) Except as provided in paragraphs (b), (c), (d), or (j) 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] TP12JN08.055

Where:

Es = SO2 emission limit, in ng/J or lb/MMBtu 
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).


For facilities complying with the percent reduction standard, only the 
heat input supplied to the affected facility from the combustion of 
coal and oil is counted under this paragraph. 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. For 
facilities complying with the percent reduction standard, only the heat 
input supplied to the affected facility from the combustion of coal and 
oil is counted under this paragraph. 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.
    (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] TP12JN08.056

Where:

Es = SO2 emission limit, in ng/J or lb/MMBtu 
heat input;
Kc = 260 ng/J (or 0.60 lb/MMBtu);
Kd = 170 ng/J (or 0.40 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).


For facilities complying with the percent reduction standard, only the 
heat input supplied to the affected facility from the combustion of 
coal and oil is counted under this paragraph. 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

[[Page 33654]]

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. For facilities complying with paragraphs 
(d)(1), (2), or (3) of this section, only the heat input supplied to 
the affected facility from the combustion of coal and oil is counted 
under this paragraph. 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.
* * * * *
    (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. For 
facilities complying with the percent reduction standard and paragraph 
(k)(3), only the heat input supplied to the affected facility from the 
combustion of coal and oil is counted under paragraph (k) of 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.
    (2) Units firing only very low sulfur oil, gaseous fuel, a mixture 
of these fuels, or a mixture of these fuels with any other 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, oil, or natural gas 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 or natural gas.
* * * * *
    14. Section 60.43b is amended to read as follows:
    a. By revising paragraph (f);
    b. By revising paragraphs (h)(1), (h)(5), and adding new paragraph 
(h)(6).


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

* * * * *
    (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 can 
combust 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.
* * * * *
    (h)(1) Except as provided in paragraphs (h)(2), (h)(3), (h)(4), 
(h)(5), and (h)(6) 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.
* * * * *
    (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, an owner or operator of an affected facility not 
located in a noncontinental area that commences construction, 
reconstruction, or modification after February 28, 2005, and that 
combusts only oil that contains no more than 0.30 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 not 
subject to the PM limits under Sec.  60.43b(h)(1).
    (6) 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, an owner or operator of an affected facility located 
in a noncontinental area 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, 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 not subject to the PM limits 
under Sec.  60.43b(h)(1).
    15. Section 60.44b is amended by revising paragraph (l)(1) to read 
as follows:


Sec.  60.44  Standard for nitrogen oxides (NOX).

* * * * *
    (l) * * *
    (1) If the affected facility combusts coal, oil, natural gas, a 
mixture of these fuels, or a mixture of these fuels with any other 
fuels: A limit of 86 ng/J (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
* * * * *
    16. Section 60.45b is amended to read as follows:
    a. By revising paragraph (a);
    b. By revising paragraph (d) introductory text;
    c. By revising paragraph (j); and
    d. By revising paragraph (k).


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 are allowed to exceed the 
limit 30 operating days per calendar year for SO2 control system 
maintenance.
* * * * *
    (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, natural gas, or a mixture of these fuels, 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

[[Page 33655]]

to an annual capacity factor for oil of 10 percent (0.10) or less 
shall:
* * * * *
    (j) The owner or operator of an affected facility that only 
combusts very low sulfur oil, natural gas, or a mixture of these fuels 
with any other fuels not subject to an SO2 standard 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), 
60.42b(k)(2), and 60.42b(k)(3) (when not burning coal) shall follow the 
applicable procedures under Sec.  60.49b(r).
    17. Section 60.46b is amended to read as follows:
    a. By revising paragraphs (e)(2) and (e)(4);
    b. By revising paragraph (i);
    c. By revising paragraphs (j) introductory text and (j)(11) and 
adding new paragraph (j)(14) to read as follows:


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

* * * * *
    (e) * * *
    (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 (except as specified under Sec.  60.46b(e)(4)) 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.
* * * * *
    (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, gasified coal, 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.
* * * * *
    (i) The owner or operator of an affected facility seeking to 
demonstrate compliance with the PM limit under paragraphs Sec.  
60.43b(a)(4) or Sec.  60.43b(h)(5) shall follow the applicable 
procedures under Sec.  60.49b(r).
    (j) In place of PM testing with Method 5 or 5B of appendix A-3 of 
this part, or Method 17 of appendix A-6 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 Method 5 or 5B of appendix A-3 of this part 
or Method 17 of appendix A-6 of this part shall comply with the 
requirements specified in paragraphs (j)(1) through (j)(14) of this 
section.
* * * * *
    (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 conducting performance tests using the following test 
methods.
    (i) For PM, Method 5 or 5B of appendix A-3 of this part or Method 
17 of appendix A-6 of this part shall be used; and
    (ii) For condensable PM emissions, Method 202 of appendix M of part 
51 shall be used; and
    (iii) For visible emissions, Method 9 of Appendix A-4 shall be 
used; and
    (iv) For O2 (or CO2), Method 3, 3A, or 3B of 
appendix A-2 of this part, as applicable shall be used.
* * * * *
    (14) Within 90 days after the date of completing each performance 
evaluation required by paragraph (c)(11) of this section, the owner or 
operator of the affected facility must submit the test data to EPA by 
successfully entering the data electronically into EPA's WebFire data 
base available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. If the owner or operator is unsuccessful in 
entering the test data into EPA's WebFire data base, then the owner or 
operator must submit monthly reports to EPA until the data is 
successfully submitted to WebFire. The monthly reports shall describe 
the difficulty preventing successful submittal of the data and what 
actions are being taken to correct the problem.
    18. Section 60.47b is amended by revising paragraphs (a) 
introductory text and (e)(4)(i) to read as follows:


Sec.  60.47b  Emission monitoring for sulfur dioxide.

    (a) Except as provided in paragraphs (b) and (f) 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. If the owner or operator 
has installed and certified SO2 and O2 or 
CO2 CEMS according to the requirements of Sec.  75.20(c)(1) 
of this chapter and appendix A to part 75 of this chapter, and is 
continuing to meet the ongoing quality assurance requirements of Sec.  
75.21 of this chapter and appendix B to part 75 of this chapter, those 
CEMS may be used to meet the requirements of this section, provided 
that:
* * * * *
    (e) * * *
    (4) * * *
    (i) For all required CO2 and O2 monitors and 
for SO2 and NOX monitors with span values greater 
than or equal to 100 ppm, the daily calibration error test and 
calibration adjustment procedures described in sections 2.1.1 and 2.1.3 
of appendix B to part 75 of this chapter may be followed instead of the 
CD assessment procedures in Procedure 1, section 4.1 of appendix F to 
this part. If this option is selected, the data validation and out-of-
control provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75 
of this chapter shall be followed instead of the excessive CD and out-
of-control criteria in Procedure 1, section 4.3 of appendix F to this 
part. For the purposes of data validation under this subpart, the 
excessive CD and out-of-control criteria in Procedure 1, section 4.3 of 
appendix F to this part shall apply to SO2 and 
NOX span values less than 100 ppm;
* * * * *

[[Page 33656]]

    19. Section 60.48b is amended to read as follows:
    a. By revising paragraph (a);
    b. By revising paragraph (g) introductory text;
    c. By revising paragraph (h) introductory text; and
    d. By revising paragraph (k) introductory text.


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 
COMS for measuring the opacity of emissions discharged to the 
atmosphere and record the output of the system. The owner or operator 
of an affected facility subject to an opacity standard under Sec.  
60.43b and meeting the conditions under paragraphs (j)(1), (2), (3), or 
(4) of this section who elects not to install a COMS shall comply with 
either paragraph (a)(1), (a)(2), or (a)(3) of this section.
    (1) Conduct a performance test using Method 9 of Appendix A-4 of 
this part and the procedures in Sec.  60.11 to demonstrate compliance 
with the applicable limit in Sec.  60.43b. The Method 9 observations 
must be completed, at a minimum, every 12 months; or
    (2) Conduct a series of three 1-hour observations (during normal 
operation) using Method 22 of Appendix A-7 of this part at the affected 
facility and demonstrate that the sum of the occurrences of any visible 
emissions is not in excess of 5 percent of the observation period 
(i.e., 9 minutes per 3-hour period). The Method 22 observations must be 
completed, at a minimum, every 12 months. If the sum of the occurrences 
of any visible emissions is in excess of 5 percent of the observation 
period, then the owner or operator shall conduct a new performance test 
within 24 hours according to the requirements in Sec.  60.46b(d)(7); or
    (3) Monitor opacity using a digital opacity compliance system 
according to a site-specific monitoring plan approved by the 
Administrator. The observations should include at least one digital 
image every 15 seconds for three separate 1-hour periods (during normal 
operation) every 12 months. An approvable monitoring plan should 
include a demonstration that the occurrences of visible emissions are 
not in excess of 5 percent of the observation period (i.e., 36 
observations per 3-hour period). For reference purposes in preparing 
the monitoring plan, see OAQPS ``Determination of Visible Emission 
Opacity from Stationary Sources Using Computer-Based Photographic 
Analysis Systems.'' This document is available from the U.S. 
Environmental Protection Agency (U.S. EPA); Office of Air Quality and 
Planning 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 Preliminary Methods. If the sum of the 
occurrences of any visible emissions is in excess of 5 percent of the 
observation period, then the owner or operator shall conduct a new 
performance test within 24 hours according to the requirements in Sec.  
60.46b(d)(7).
* * * * *
    (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, gasified coal, or 
any mixture of these fuels, greater than 10 percent (0.10) shall:
* * * * *
    (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), Sec.  60.44b(e), or Sec.  60.44b(l) is not required to 
install or operate a continuous emissions monitoring system to measure 
NOX emissions.
* * * * *
    (k) Owners or operators complying with the PM emission limit by 
using a PM CEMS must calibrate, maintain, operate, 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.
    20. Section 60.49b is amended to read as follows:
    a. By revising paragraphs (c) introductory text and (c)(3);
    b. By revising paragraphs (h) introductory text, (h)(1),(h)(2) 
introductory text and (h)(2)(i);
    c. By revising paragraph (k)(2); and
    d. By revising paragraph (r) introductory text and(r)(1).


Sec.  60.49b  Reporting and recordkeeping requirements.

* * * * *
    (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(h). 
This plan shall be submitted to the Administrator for approval within 
360 days of the initial startup of the affected facility. An affected 
facility burning coke oven gas alone or in combination with other 
gaseous fuels or distillate oil shall submit this plan to the 
Administrator for approval within 360 days of the initial startup of 
the affected facility or by May 31, 2009, whichever date comes later. 
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:
* * * * *
    (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(h).
* * * * *
    (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(f) 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, gasified coal, or 
residual oil with a nitrogen content of 0.3 weight percent or less; or
* * * * *
    (k) * * *
    (2) Each 30-day average SO2 emission rate (ng/J or lb/MMBtu heat 
input) measured during the reporting period, ending with the last 30-
day period;

[[Page 33657]]

reasons for noncompliance with the emission standards; and a 
description of corrective actions taken; For an exceedance due to 
maintenance of the SO2 control system covered under paragraph 
60.45b(a), the report shall identify the days on which the maintenance 
was performed and a description of the maintenance;
* * * * *
    (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 and/or natural gas under Sec.  60.42b(j) or Sec.  60.42b(k) 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 and gaseous fuel meets the definition of natural gas 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 natural gas was 
combusted in the affected facility during the reporting period; or
* * * * *

Subpart Dc--[Amended]

    21. Section 60.41c is amended by revising the definitions of 
``Coal,'' ``Distillate oil,'' ``Natural gas,'' and ``Steam generating 
unit'' to read as follows:


Sec.  60.41c  Definitions.

* * * * *
    Coal means all solid fuels classified as anthracite, bituminous, 
subbituminous, or lignite by the American Society of Testing and 
Materials in ASTM D388 (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 not meeting the 
definition of natural gas, coal-oil mixtures, and coal-water mixtures, 
are also included in this definition for the purposes of this subpart.
* * * * *
    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) or diesel fuel oil as defined by the American Society for 
Testing and Materials in ASTM D975 (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) liquefied petroleum (LP) gas, as defined by the American 
Society for 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 dry standard cubic meter (910 and 
1,150 Btu per dry standard cubic foot).
* * * * *
    Steam generating unit means a device that combusts any fuel and 
produces steam or heats water or heats any 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.
* * * * *
    22. Section 60.42c is amended by revising paragraphs (e)(2) and (j) 
to read as follows:


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

* * * * *
    (e) * * *
    (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] TP12JN08.057

Where:
Es= SO2 emission limit, expressed in ng/J or 
lb/MMBtu heat input;
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 = Heat input from the combustion of oil, in J (MMBtu).
* * * * *
    (j) For affected facilities located in noncontinental areas and 
affected facilities complying with the percent reduction standard, 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.
    23. Section 60.43c is amended by revising paragraph (c) to read as 
follows:


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

* * * * *
    (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 can 
combust 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.
* * * * *
    24. Section 60.44c is amended by revising paragraph (h) to read as 
follows:


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

* * * * *
    (h) For affected facilities subject to Sec.  60.42c(h)(1), (2), or 
(3) where the owner or operator seeks to demonstrate compliance with 
the SO2 standards based on fuel supplier certification, the performance 
test shall consist of the certification from the fuel supplier, as 
described under Sec.  60.48c(f), as applicable.
* * * * *
    25. Section 60.45c is amended to read as follows:
    a. By revising paragraph (a)(8);
    b. By revising paragraphs (c) introductory text, (c)(7), (c)(8), 
(c)(9), (c)(11), and adding new paragraph (c)(14) to read as follows:


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

    (a) * * *
    (8) Method 9 of appendix A-4 of this part shall be used for 
determining the opacity of stack emissions.
* * * * *
    (c) In place of PM testing with Method 5 or 5B of appendix A-3 of 
this part or Method 17 of appendix A-6 of this part, an owner or 
operator may elect to install, calibrate, maintain, and operate a CEMS 
for monitoring PM emissions

[[Page 33658]]

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 
Method 5 or 5B of appendix A-3 of this part or Method 17 of appendix A-
6 of this part shall install, calibrate, maintain, and operate a CEMS 
and shall comply with the requirements specified in paragraphs (c)(1) 
through (c)(14) of this section.
* * * * *
    (7) At a minimum, valid CEMS hourly averages shall be obtained as 
specified in paragraph (c)(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 (c)(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 (c)(7) of this section are not met.
* * * * *
    (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 conducting 
performance tests using the following test methods.
    (i) For PM, Method 5 or 5B of appendix A-3 of this part or Method 
17 of appendix A-6 of this part shall be used; and
    (ii) For condensable PM emissions, Method 202 of appendix M of part 
51 shall be used; and
    (iii) For visible emissions, Method 9 of Appendix A-4 shall be 
used; and
    (iv) For O2 (or CO2), test Method 3, 3A, or 3B of appendix A-2 of 
this part, as applicable shall be used.
* * * * *
    (14) Within 90 days after the date of completing each performance 
evaluation required by paragraph (c)(11) of this section, the owner or 
operator of the affected facility must submit the test data to EPA by 
successfully entering the data electronically into EPA's WebFire data 
base available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. If the owner or operator is unsuccessful in 
entering the test data into EPA's WebFire data base, then the owner or 
operator must submit monthly reports to EPA until the data is 
successfully submitted to WebFire. The monthly reports shall describe 
the difficulty preventing successful submittal of the data and what 
actions are being taken to correct the problem.
* * * * *
    26. Section 60.47c is amended to read as follows:
    a. By revising paragraph (a);
    b. By revising paragraph (c) introductory text;
    c. By revising paragraph (d) introductory text;
    d. By revising paragraph (e) introductory text; and
    e. By revising paragraph (f) introductory text.


Sec.  60.47c  Emission monitoring for particulate matter.

    (a) Except as provided in paragraphs (c), (d), (e), and (f) 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. The owner or operator of an affected 
facility subject to an opacity standard under Sec.  60.43c(c) and that 
is not required to install a COMS to measure opacity due to paragraphs 
(c), (d), or (e) of this section that elects not to install a COMS 
shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this 
section.
    (1) Conduct a performance test using Method 9 of Appendix A-4 of 
this part and the procedures in Sec.  60.11 to demonstrate compliance 
with the applicable limit in Sec.  60.43c. The Method 9 observations 
must be completed, at a minimum, every 12 months; or
    (2) Conduct a series of three 1-hour observations (during normal 
operation) using Method 22 of Appendix A-7 of this part at the affected 
facility and demonstrate that the sum of the occurrences of any visible 
emissions is not in excess of 5 percent of the observation period 
(i.e., 9 minutes per 3-hour period). The Method 22 observations must be 
completed, at a minimum, every 12 months. If the sum of the occurrences 
of any visible emissions is in excess of 5 percent of the observation 
period, then the owner or operator shall conduct a new performance test 
within 24 hours according to the requirements in Sec.  60.45c(a)(8); or
    (3) Monitor opacity using a digital opacity compliance system 
according to a site-specific monitoring plan approved by the 
Administrator. The observations should include at least one digital 
image every 15 seconds for three separate 1-hour periods (during normal 
operation) every 12 months. An approvable monitoring plan should 
include a demonstration that the occurrences of visible emissions are 
not in excess of 5 percent of the observation period (i.e., 36 
observations per 3-hour period). For reference purposes in preparing 
the monitoring plan, see OAQPS ``Determination of Visible Emission 
Opacity From Stationary Sources Using Computer-Based Photographic 
Analysis Systems.'' This document is available from the U.S. 
Environmental Protection Agency (U.S. EPA); Office of Air Quality and 
Planning 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 Preliminary Methods. If the sum of the 
occurrences of any visible emissions is in excess of 5 percent of the 
observation period, then the owner or operator shall conduct a new 
performance test within 24 hours according to the requirements in Sec.  
60.450c(a)(8).
* * * * *
    (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 and that are subject to an opacity standard 
under Sec.  60.43c(c) 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 must calibrate, maintain, operate, and record the 
output of the system for PM emissions discharged to the atmosphere as 
specified in Sec.  60.45c(c). The CEMS specified in paragraph Sec.  
60.45c(c) 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.
    (e) An affected facility that is subject to an opacity standard 
under Sec.  60.43c(c)

[[Page 33659]]

and that does not use post-combustion technology (except a wet 
scrubber) for reducing PM, SO2, or carbon monoxide (CO) emissions, 
burns only gaseous fuels or fuel oils that contain less than or equal 
to 0.50 weight percent sulfur, and is operated such that emissions of 
CO to the atmosphere from the affected facility are maintained at 
levels less than or equal to 0.15 lb/MMBtu on a boiler operating day 
average basis is not required to operate a COMS for measuring opacity. 
Owners and operators of affected facilities electing to comply with 
this paragraph must demonstrate compliance according to the procedures 
specified in paragraphs (e)(1) through (4) of this section.
* * * * *
    (f) An affected facility that is subject to an opacity standard 
under Sec.  60.43c(c) and that burns only gaseous fuels or fuel oils 
that contain less than or equal to 0.50 weight percent sulfur and 
operates according to a written site-specific monitoring plan approved 
by the permitting authority is not required to operate a COMS for 
measuring opacity. This monitoring plan must include procedures and 
criteria for establishing and monitoring specific parameters for the 
affected facility indicative of compliance with the opacity standard.
    27. Section 60.48c is amended by revising paragraph (e)(11) to read 
as follows:


Sec.  60.48c  Reporting and Recordkeeping requirements.

* * * * *
    (e) * * *
    (11) If 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.
* * * * *
[FR Doc. E8-12621 Filed 6-11-08; 8:45 am]
BILLING CODE 6560-50-P