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ENVIRONMENTAL PROTECTION AGENCY
Veterans Affairs Department
CFR Citation: 40 CFR Part 60
RIN ID: RIN 2060-AO61
EPA ID: [EPA-HQ-OAR-2005-0031; FRL-8576-2]
NOTICE: Part VI
DOCUMENT ACTION: Proposed rule.
SUBJECT CATEGORY: 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
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.
DOCUMENT SUMMARY: EPA is proposing to amend the new source performance standards for electric utility steam generating units and industrialcommercial 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.
SUMMARY: Environmental Protection Agency,
SUPPLEMENTAL INFORMATION
Regulated Entities. Entities potentially affected by this proposed action include, but are not limited to, the following:
Examples of regulated
Category NAICS \1\ entities
Industry...................... 221112 Fossil fuelfired
electric utility
steam generating units.
Federal Government............ 22112 Fossil fuelfired
electric utility
steam generating
units owned by the
Federal Government.
State/local/tribal government. 22112 Fossil fuelfired
electric utility
steam generating
units owned by
municipalities.
921150 Fossil fuelfired
electric utility
steam generating
units located in
Indian Country. [[Page 33643]]
Any industrial, commercial, or 211 Extractors of crude
institutional facility using 321 petroleum and natural a steam generating unit as 322 gas.
defined in 60.40b or 60.40c. 325 Manufacturers of
324 lumber and wood
products.
Pulp and paper mills. Chemical
manufacturers.
Petroleum refiners and
manufacturers of coal
products.
316, 326, 339 Manufacturers of
rubber and
miscellaneous plastic
products.
331 Steel works, blast
furnaces.
332 Electroplating,
plating, polishing,
anodizing, and
coloring.
336 Manufacturers of motor
vehicle parts and
accessories.
221 Electric, gas, and
sanitary services.
622 Health services.
611 Educational Services.
\1\ North American Industry Classification System (NAICS) code.
This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by the proposed rule. To determine whether your facility is regulated by the proposed rule, you should examine the applicability criteria in Sec. 60.40a, Sec. 60.40b, or Sec. 60.40c of 40 CFR part 60. If you have any questions regarding the applicability of the proposed rule to a particular entity, contact the person listed in the preceding FOR FURTHER INFORMATION CONTACT section.
WorldWide Web (WWW). Following the Administrator's signature, a copy of the proposed amendments will be posted on the Technology Transfer Network's (TTN) policy and guidance page for newly proposed or promulgated rules at http://www.epa.gov/ttn/oarpg. The TTN provides information and technology exchange in various areas of air pollution control.
Public Hearing. If a public hearing is requested, it will be held at 10 a.m. at the EPA Facility Complex in Research Triangle Park, North Carolina or at an alternate site nearby. Contact Mr. Christian Fellner at 9195414003 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 LowIncome 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 longterm emissions reductions in numerous industries by
assuring costeffective 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 nonair 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, crossreference 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 ComputerBased Photographic Analysis Systems'' found at http://www.epa.gov/tnn/emc/prelim/pre008.pdf. For this third option, the facility owner/operator would prepare a sitespecific 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 liquidtogas 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 fuelbased 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 (SO
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 30day
SO
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 SO
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, oilfired
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 sitespecific 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 oilfired 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 SO
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 sourcespecific 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 oilfired steam generating units located in noncontinental areas to
incur high fuel transportation costs or to install post combustion
controls on oilfired boilers. The proposed amendments to the
definition of very low sulfur oil and the corresponding low sulfur oil
PM exemption and SO
We are proposing that gasified coal (including COG) have the same NO
[[Page 33646]]
monitoring option as natural gas, distillate oil, and low nitrogen content residual oil since gasified coal has uncontrolled
NO
Because of the specific characteristics of the steel industry, the
current regulations allow a 30day exceedance per year from the
SO
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, NO
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.
\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.
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 20600023 for 40 CFR part 60, subpart Da, 20600072 for 40 CFR part 60, subpart Db, and 20600202 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 notforprofit 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 1044, 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 costbenefit 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 costeffective 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 5501 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. 104113 (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 D97508, ``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 194282959.
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
potentiallyapplicable 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 LowIncome 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 lowincome 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 lowincome 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 lowincome 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 D97508, 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 (SO
* * * * *
(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 fossilfuelfired steam generator that burns only gaseous
or liquid fossil fuel (excluding residual oil) with potential
SO
* * * * *
(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 A4 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 1hour observations (during normal
operation) using Method 22 of Appendix A7 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 3hour 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 sitespecific monitoring plan approved by the
Administrator. The observations should include at least one digital
image every 15 seconds for three separate 1hour 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 3hour period). For reference purposes in preparing
the monitoring plan, see OAQPS ``Determination of Visible Emission
Opacity from Stationary Sources Using ComputerBased 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 (D24302), 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 threehour period during which the average emissions
(arithmetic average of three contiguous onehour periods) of
SO
(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 onehour periods during the 30
operating days) of SO
(3) Nitrogen oxides. Excess emissions for affected facilities using a CEMS for measuring NO
(i) For affected facilities electing not to comply with Sec.
60.44(e), any threehour period during which the average emissions
(arithmetic average of three contiguous onehour 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 onehour periods during the 30
operating days) of NO
(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 onehour 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 A3 of this part shall be used to
determine PM concentration (C) at affected facilities without wet flue
gasdesulfurization (FGD) systems and Method 5B of appendix A3 of this
part shall be used to determine the PM concentration (C) after FGD
systems. Method 5 or 5B of appendix A3 of this part, Method 17 of
appendix A6 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 A3 of this
part may be used with Method 17 of appendix A6 of this part only if it
is used after wet FGD systems. Method 17 of appendix A6 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
steamgenerating 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 6minute 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 24hour average opacity level
measured by the COMS each boiler operating day excluding periods of
affected facility startup, shutdown, or malfunction. If the measured
24hour 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 24hour 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 liquidtogas 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 24hour 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 24hour 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 liquidtogas 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 sitespecific 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 SO
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 SO
(iii) The affected facility does not use postcombustion technology
(except a wet scrubber) for reducing PM, SO
(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 A4 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 1hour observations (during normal
operation) using Method 22 of appendix A7 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 3hour 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 sitespecific monitoring plan approved by the
Administrator. The observations should include at least one digital
image every 15 seconds for three separate 1hour 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 3hour period). For reference purposes in preparing
the monitoring plan, see OAQPS ``Determination of Visible Emission
Opacity from Stationary Sources Using ComputerBased 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 (D24302), 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 outputbased 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 inputbased 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
FOR FURTHER INFORMATION CONTACT Mr. Christian Fellner, Energy Strategies Group, Sector Policies and Programs Division (D24301), U.S. EPA, Research Triangle Park, NC 27711, telephone number (919) 5414003, facsimile number (919) 5415450, electronic mail (email) address: fellner.christian@epa.gov.
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