[Federal Register Volume 73, Number 114 (Thursday, June 12, 2008)]
[Proposed Rules]
[Pages 33642-33659]
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:
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Examples of regulated
Category NAICS \1\ entities
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Industry...................... 221112 Fossil fuel-fired
electric utility
steam generating
units.
Federal Government............ 22112 Fossil fuel-fired
electric utility
steam generating
units owned by the
Federal Government.
State/local/tribal government. 22112 Fossil fuel-fired
electric utility
steam generating
units owned by
municipalities.
921150 Fossil fuel-fired
electric utility
steam generating
units located in
Indian Country.
[[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.
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\1\ North American Industry Classification System (NAICS) code.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by the
proposed rule. To determine whether your facility is regulated by the
proposed rule, you should examine the applicability criteria in Sec.
60.40a, Sec. 60.40b, or Sec. 60.40c of 40 CFR part 60. If you have
any questions regarding the applicability of the proposed rule to a
particular entity, contact the person listed in the preceding FOR
FURTHER INFORMATION CONTACT section.
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