[Federal Register Volume 69, Number 44 (Friday, March 5, 2004)]
[Rules and Regulations]
[Pages 10512-10548]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-4530]
[[Page 10511]]
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Part II
Environmental Protection Agency
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40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants for Stationary
Combustion Turbines; Final Rule
Federal Register / Vol. 69, No. 44 / Friday, March 5, 2004 / Rules
and Regulations
[[Page 10512]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[OAR-2002-0060; FRL-7554-2]
RIN 2060-AG-67
National Emission Standards for Hazardous Air Pollutants for
Stationary Combustion Turbines
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: This action promulgates national emission standards for
hazardous air pollutants (NESHAP) for stationary combustion turbines.
We have identified stationary combustion turbines as major sources of
hazardous air pollutants (HAP) emissions such as formaldehyde, toluene,
benzene, and acetaldehyde. The NESHAP will implement section 112(d) of
the Clean Air Act (CAA) by requiring all major sources to meet HAP
emission standards reflecting the application of the maximum achievable
control technology (MACT) for combustion turbines. In the final NESHAP,
we have divided the stationary combustion turbine category into eight
subcategories, including lean premix gas-fired turbines, lean premix
oil-fired turbines, diffusion flame gas-fired turbines, diffusion flame
oil-fired turbines, emergency turbines, turbines with a rated peak
power output of less than 1.0 megawatt (MW), turbines burning landfill
or digester gas, and turbines located on the North Slope of Alaska. We
have also adopted a final emission standard requiring control of
formaldehyde emissions for all new or reconstructed stationary
combustion turbines in the four lean premix and diffusion flame
subcategories. We estimate that 20 percent of the stationary combustion
turbines affected by the final rule will be located at major sources.
As a result, the environmental, energy, and economic impacts presented
in this preamble reflect these estimates. The final rule will protect
public health by reducing exposure to air pollution, by reducing total
national HAP emissions by an estimated 98 tons per year (tpy) in the
5th year after the rule is promulgated.
EFFECTIVE DATE: March 5, 2004.
ADDRESSES: Docket. Docket ID No. OAR-2002-0060 (paper docket No. A-95-
51) contains supporting information used in developing the standards.
The docket is located at the U.S. EPA, 1301 Constitution Avenue, NW.,
Washington, DC 20460 in room B102, and may be inspected from 8:30 a.m.
to 4:30 p.m., Monday through Friday, excluding legal holidays.
FOR FURTHER INFORMATION CONTACT: For further information concerning
applicability and rule determinations, contact the appropriate State or
local agency representative. For information concerning the analyses
performed in developing the NESHAP, contact Mr. Sims Roy, Combustion
Group, Emission Standards Division (MD-C439-01), U.S. EPA, Research
Triangle Park, North Carolina 27711; telephone number (919) 541-5263;
facsimile number (919) 541-5450; electronic mail address
``[email protected].''
SUPPLEMENTARY INFORMATION: Regulated Entities. Categories and entities
potentially regulated by this action include:
------------------------------------------------------------------------
Examples of
Category SIC NAICS regulated entities
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Any industry using a stationary 4911 2211 Electric power
combustion turbine as defined in generation,
the regulation. transmission, or
distribution
4922 486210 Natural gas
transmission
1311 211111 Crude petroleum and
natural gas
production
1321 211112 Natural gas liquids
producers
4931 221 Electric and other
services combined
------------------------------------------------------------------------
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. To determine whether your facility is regulated by this action,
you should examine the applicability criteria in Sec. 63.6085 of the
final rule. If you have any questions regarding the applicability of
this action to a particular entity, consult the person listed in the
preceding FOR FURTHER INFORMATION CONTACT section.
Docket. The EPA has established an official public docket for this
action under Docket ID No. OAR-2002-0060 (A-95-51). The official public
docket consists of the documents specifically referenced in this
action, any public comments received, and other information related to
this action. Although a part of the official docket, the public docket
does not include Confidential Business Information (CBI) or other
information whose disclosure is restricted by statute. The official
public docket is the collection of materials that is available for
public viewing at the Air and Radiation Docket in the EPA Docket
Center, (EPA/DC) EPA West, Room B102, 1301 Constitution Ave., NW.,
Washington, DC 20460. The EPA Docket Center 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 Reading Room is (202) 566-1744,
and the telephone number for the Air and Radiation Docket is (202) 566-
1742. A reasonable fee may be charged for copying docket materials.
Electronic Access. You may access this Federal Register document
electronically through the EPA Internet under the ``Federal Register''
listings at http://www.epa.gov/fedrgstr/.
An electronic version of the public docket is available through
EPA's electronic public docket and comment system, EPA Dockets. You may
use EPA Dockets at http://www.epa.gov/edocket/ to view public comments,
access the index listing of the contents of the official public docket,
and to access those documents in the public docket that are available
electronically. Although not all docket materials may be available
electronically, you may still access any of the publicly available
docket materials through the docket facility identified above. Once in
the system, select ``search,'' then key in the appropriate docket
identification number.
Judicial Review. Under section 307(b)(1) of the CAA, judicial
review of the final NESHAP is available only by filing a petition for
review in the U.S. Court of Appeals for the District of Columbia
Circuit by May 4, 2004. Under section 307(d)(7)(B) of the CAA, only an
objection to a rule or procedure raised with reasonable specificity
during the period for public comment can be raised during judicial
review. Moreover, under section 307(b)(2) of the CAA, the requirements
established by the final rule may not be challenged separately in any
civil or criminal proceeding brought to enforce these requirements.
Background Information Document. The EPA proposed the NESHAP for
stationary combustion turbines on January 14, 2003 (68 FR 1888), and
[[Page 10513]]
received 75 comment letters on the proposal. A background information
document (BID) (``National Emission Standards for Stationary Combustion
Turbines, Summary of Public Comments and Responses,'') containing EPA's
responses to each public comment is available in Docket ID No. OAR-
2002-0060 (A-95-51).
Outline. The information presented in this preamble is organized as
follows:
I. Background
A. What is the Source of Authority for Development of NESHAP?
B. What Criteria are Used in the Development of NESHAP?
C. What are the Health Effects Associated with HAP from
Stationary Combustion Turbines?
D. What is the Regulatory Development Background of the Source
Category?
II. Summary of the Final Rule
A. What Sources are Subject to the Final Rule?
B. What Source Categories and Subcategories are Affected by the
Final Rule?
C. What are the Primary Sources of HAP Emissions and What are
the Emissions?
D. What are the Emission Limitations and Operating Limitations?
E. What are the Initial Compliance Requirements?
F. What are the Continuous Compliance Provisions?
G. What are the Notification, Recordkeeping and Reporting
Requirements?
III. Summary of Responses to Major Comments
A. Applicability
B. Definitions
C. Dates
D. MACT
E. Emission Limitations
F. Monitoring, Recordkeeping, and Reporting
G. Test Methods
H. Risk-Based Approaches
I. Other
IV. Rationale for Selecting the Final Standards
A. How did we Select the Source Category and any Subcategories?
B. What are the Requirements for Stationary Combustion Turbines
Located at Area Sources?
C. What is the Affected Source?
D. How did we Determine the Basis and Level of the Emission
Limitations for Existing Sources?
E. How did we Determine the Basis and Level of the Emission
Limitations and Operating Limitations for New Sources?
F. How did we Select the Initial Compliance Requirements?
G. How did we Select the Continuous Compliance Requirements?
H. How did we Select the Testing Methods to Measure these Low
Concentrations of Formaldehyde?
I. How did we Select the Notification, Recordkeeping and
Reporting Requirements?
V. Summary of Environmental, Energy and Economic Impacts
A. What are the Air Quality Impacts?
B. What are the Cost Impacts?
C. What are the Economic Impacts?
D. What are the Non-air Health, Environmental and Energy
Impacts?
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act of 1995
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 Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations that
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Congressional Review Act
I. Background
A. What is the Source of Authority for Development of NESHAP?
Section 112 of the CAA requires us to list categories and
subcategories of major sources and area sources of HAP and to establish
NESHAP for the listed source categories and subcategories. The
stationary turbine source category was listed on July 16, 1992 (57 FR
31576). Major sources of HAP are those that have the potential to emit
greater than 10 tpy of any one HAP or 25 tpy of any combination of HAP.
B. What Criteria are Used in the Development of NESHAP?
Section 112 of the CAA requires that we establish NESHAP for the
control of HAP from both new and existing major sources. The CAA
requires the NESHAP to reflect the maximum degree of reduction in
emissions of HAP that is achievable. This level of control is commonly
referred to as the MACT.
The MACT floor is the minimum control level allowed for NESHAP and
is defined under section 112(d)(3) of the CAA. In essence, the MACT
floor ensures that the standard is set at a level that assures that all
major sources achieve the level of control at least as stringent as
that already achieved by the better controlled and lower emitting
sources in each source category or subcategory. For new sources, the
MACT standards cannot be less stringent than the emission control that
is achieved in practice by the best controlled similar source. The MACT
standards for existing sources can be less stringent than standards for
new sources, but they cannot be less stringent than the average
emission limitation achieved by the best performing 12 percent of
existing sources in the category or subcategory (or the best performing
five sources for categories or subcategories with fewer than 30
sources).
In developing MACT, we also consider control options that are more
stringent than the floor. We may establish standards more stringent
than the floor based on the consideration of cost of achieving the
emissions reductions, any non-air quality health and environmental
impacts, and energy requirements.
C. What are the Health Effects Associated with HAP from Stationary
Combustion Turbines?
Emission data collected during development of the NESHAP show that
several HAP are emitted from stationary combustion turbines. These HAP
emissions are formed during combustion or result from HAP compounds
contained in the fuel burned.
Among the HAP which have been measured in emission tests that were
conducted at natural gas fired and distillate oil fired combustion
turbines are: 1,3 butadiene, acetaldehyde, acrolein, benzene,
ethylbenzene, formaldehyde, naphthalene, poly aromatic hydrocarbons
(PAH) propylene oxide, toluene, and xylenes. Metallic HAP from
distillate oil fired stationary combustion turbines that have been
measured are: arsenic, beryllium, cadmium, chromium, lead, manganese,
mercury, nickel, and selenium. Natural gas fired stationary combustion
turbines do not emit metallic HAP.
Although numerous HAP may be emitted from combustion turbines, only
a few account for essentially all the mass of HAP emissions from
stationary combustion turbines. These HAP are: formaldehyde, toluene,
benzene, and acetaldehyde.
The HAP emitted in the largest quantity is formaldehyde.
Formaldehyde is a probable human carcinogen and can cause irritation of
the eyes and respiratory tract, coughing, dry throat, tightening of the
chest, headache, and heart palpitations. Acute inhalation has caused
bronchitis, pulmonary edema, pneumonitis, pneumonia, and death due to
respiratory failure. Long-term exposure can cause dermatitis and
sensitization of the skin and respiratory tract.
Other HAP emitted in significant quantities from stationary
combustion turbines include toluene, benzene, and acetaldehyde. The
health effect of primary concern for toluene is dysfunction of the
central nervous system (CNS). Toluene vapor also
[[Page 10514]]
causes narcosis. Controlled exposure of human subjects produced mild
fatigue, weakness, confusion, lacrimation, and paresthesia; at higher
exposure levels there were also euphoria, headache, dizziness, dilated
pupils, and nausea. After-effects included nervousness, muscular
fatigue, and insomnia persisting for several days. Acute exposure may
cause irritation of the eyes, respiratory tract, and skin. It may also
cause fatigue, weakness, confusion, headache, and drowsiness. Very high
concentrations may cause unconsciousness and death.
Benzene is a known human carcinogen. The health effects of benzene
include nerve inflammation, CNS depression, and cardiac sensitization.
Chronic exposure to benzene can cause fatigue, nervousness,
irritability, blurred vision, and labored breathing and has produced
anorexia and irreversible injury to the blood-forming organs; effects
include aplastic anemia and leukemia. Acute exposure can cause
dizziness, euphoria, giddiness, headache, nausea, staggering gait,
weakness, drowsiness, respiratory irritation, pulmonary edema,
pneumonia, gastrointestinal irritation, convulsions, and paralysis.
Benzene can also cause irritation to the skin, eyes, and mucous
membranes.
Acetaldehyde is a probable human carcinogen. The health effects for
acetaldehyde are irritation of the eyes, mucous membranes, skin, and
upper respiratory tract, and it is a CNS depressant in humans. Chronic
exposure can cause conjunctivitis, coughing, difficult breathing, and
dermatitis. Chronic exposure may cause heart and kidney damage,
embryotoxicity, and teratogenic effects.
We do not have the type of current detailed data on each of the
facilities covered by the final rule and the people living around the
facilities that would be necessary to conduct an analysis to determine
the actual population exposures to the HAP emitted from these
facilities and potential for resultant health effects. Therefore, we do
not know the extent to which the adverse health effects described above
occur in the populations surrounding these facilities. However, to the
extent the adverse effects do occur, the final rule will reduce
emissions and subsequent exposures.
D. What is the Regulatory Development Background of the Source
Category?
In September 1996, we chartered the Industrial Combustion
Coordinated Rulemaking (ICCR) advisory committee under the Federal
Advisory Committee Act (FACA). The committee's objective was to develop
recommendations for regulations for several combustion source
categories under sections 112 and 129 of the CAA. The ICCR advisory
committee, also known as the Coordinating Committee, formed Source Work
Groups for the various combustor types covered under the ICCR. One work
group, the Combustion Turbine Work Group, was formed to research issues
related to stationary combustion turbines. The Combustion Turbine Work
Group submitted recommendations, information, and data analyses to the
Coordinating Committee, which in turn considered them and submitted
recommendations and information to us. The Committee's 2-year charter
expired in September 1998. We considered the Committee's
recommendations in developing the final rule for stationary combustion
turbines.
We have received a petition from the Gas Turbine Association (GTA)
requesting that we delist certain subcategories of combustion turbines.
We have been working with GTA to improve and supplement the data
supporting this petition. Once a final determination has been made
concerning the delisting petition, we will promptly make any conforming
amendments to the Stationary Combustion Turbine NESHAP which are
warranted.
II. Summary of the Final Rule
A. What Sources are Subject to the Final Rule?
The final rule applies to you if you own or operate a stationary
combustion turbine which is located at a major source of HAP emissions.
A major source of HAP emissions is a plant site that emits or has the
potential to emit any single HAP at a rate of 10 tpy (9.07 megagrams
per year (Mg/yr)) or more or any combination of HAP at a rate of 25 tpy
(22.68 Mg/yr) or more.
Section 112(n)(4) of the CAA requires that the aggregation of HAP
for purposes of determining whether an oil and gas production facility
is major or nonmajor be done only with respect to particular sites
within the source and not on a total aggregated site basis. We
referenced the requirements of section 112(n)(4) of the CAA in our
NESHAP for Oil and Natural Gas Production Facilities in subpart HH of
40 CFR part 63. As in subpart HH, we plan to aggregate HAP emissions
for the purposes of determining a major HAP source for turbines only
with respect to particular sites within an oil and gas production
facility. The sites are called surface sites and may include a
combination of any of the following equipment: glycol dehydrators,
tanks which have potential for flash emissions, reciprocating internal
combustion engines, and combustion turbines.
The EPA acknowledges that the definition of major source in the
final rule may be different from those found in other rules, however,
this does not alter the definition of major source in other rules and,
therefore, does not affect the Oil and Natural Gas Production
Facilities NESHAP (subpart HH of 40 CFR part 63) or any other rule
applicability.
Eight subcategories have been defined within the stationary
combustion turbine source category. While all stationary combustion
turbines are subject to the final rule, each subcategory has distinct
requirements. For example, existing combustion turbines and stationary
combustion turbines with a rated peak power output of less than 1.0 MW
(at International Organization for Standardization (ISO) standard day
conditions) are not required to comply with emission limitations,
recordkeeping or reporting requirements in the final rule. New or
reconstructed combustion turbines must comply with emission
limitations, recordkeeping and reporting requirements in the final
rule. You must determine your source's subcategory to determine which
requirements apply to your source.
The final rule does not apply to stationary combustion turbines
located at an area source of HAP emissions. An area source of HAP
emissions is a contiguous site under common control that is not a major
source.
Stationary combustion turbines located at research or laboratory
facilities are not subject to the final rule if research is conducted
on the turbine itself and the turbine is not being used to power other
applications at the research or laboratory facility.
The final rule does not cover duct burners. They are part of the
waste heat recovery unit in a combined cycle system. Waste heat
recovery units, whether part of a cogeneration system or a combined
cycle system, are steam generating units and are not covered by the
final rule.
Finally, the final rule does not apply to stationary combustion
engine test cells/stands since these facilities are already covered by
another NESHAP, 40 CFR part 63, subpart PPPPP.
[[Page 10515]]
B. What Source Categories and Subcategories are Affected by the Final
Rule?
The final rule covers stationary combustion turbines. A stationary
combustion turbine includes all equipment including, but not limited
to, the turbine, the fuel, air, lubrication and exhaust gas systems,
control systems (except emissions control equipment), and any ancillary
components and sub-components comprising any simple cycle stationary
combustion turbine, any regenerative/recuperative cycle stationary
combustion turbine, or the combustion turbine portion of any stationary
combined cycle steam/electric generating system. Stationary means that
the combustion turbine is not self-propelled or intended to be
propelled while performing its function. A stationary combustion
turbine may, however, be mounted on a vehicle for portability or
transportability.
Stationary combustion turbines have been divided into the following
eight subcategories: (1) Emergency stationary combustion turbines, (2)
stationary combustion turbines which burn landfill or digester gas
equivalent to 10 percent or more of the gross heat input on an annual
basis or where gasified MSW is used to generate 10 percent or more of
the gross heat input to the stationary combustion turbine on an annual
basis, (3) stationary combustion turbines of less than 1 MW rated peak
power output, (4) stationary lean premix combustion turbines when
firing gas and when firing oil at sites where all turbines fire oil no
more than 1000 hours annually (also referred to herein as ``lean premix
gas-fired turbines''), (5) stationary lean premix combustion turbines
when firing oil at sites where all turbines fire oil more than 1000
hours annually (also referred to herein as ``lean premix oil-fired
turbines''), (6) stationary diffusion flame combustion turbines when
firing gas and when firing oil at sites where all turbines fire oil no
more than 1000 hours annually (also referred to herein as ``diffusion
flame gas-fired turbines''), (7) stationary diffusion flame combustion
turbines when firing oil at sites where all turbines fire oil more than
1000 hours annually (also referred to herein as ``diffusion flame oil-
fired turbines''), and (8) stationary combustion turbines operated on
the North Slope of Alaska (defined as the area north of the Arctic
Circle (latitude 66.5 North)).
Emergency stationary combustion turbine means any stationary
combustion turbine that operates in an emergency situation. Examples
include stationary combustion turbines used to produce power for
critical networks or equipment (including power supplied to portions of
a facility) when electric power from the local utility is interrupted,
or stationary combustion turbines used to pump water in the case of
fire or flood, etc. Emergency stationary combustion turbines do not
include stationary combustion turbines used as peaking units at
electric utilities or stationary combustion turbines at industrial
facilities that typically operate at low capacity factors. Emergency
stationary combustion turbines may be operated for the purpose of
maintenance checks and readiness testing, provided that the tests are
required by the manufacturer, the vendor, or the insurance company
associated with the turbine. Required testing of such units should be
minimized, but there is no time limit on the use of emergency
stationary sources.
Stationary combustion turbines which burn landfill or digester gas
equivalent to 10 percent or more of the gross heat input on an annual
basis or stationary combustion turbines where gasified MSW is used to
generate 10 percent or more of the gross heat input to the stationary
combustion turbine on an annual basis qualify as a separate subcategory
because the types of control available for these turbines are limited.
Stationary combustion turbines of less than 1 MW rated peak power
output were also identified as a subcategory. These small stationary
combustion turbines are few in number and, to our knowledge, none use
emission control technology to reduce HAP. Therefore, it would be
inappropriate to require HAP emission controls to be applied to them
without further information on control technology performance.
Two subcategories of stationary lean premix combustion turbines
were established: stationary lean premix combustion turbines when
firing gas and when firing oil at sites where all turbines fire oil no
more than 1000 hours annually (also referred to as ``lean premix gas-
fired turbines''), and stationary lean premix combustion turbines when
firing oil at sites where all turbines fire oil more than 1000 hours
annually (also referred to as ``lean premix oil-fired turbines''). Lean
premix technology, introduced in the 1990's, was developed to reduce
nitrogen oxide (NOX) emissions without the use of add-on
controls. In a lean premix combustor, the air and fuel are thoroughly
mixed to form a lean mixture for combustion. Mixing may occur before or
in the combustion chamber. Lean premix combustors emit lower levels of
NOX, carbon monoxide (CO), formaldehyde and other HAP than
diffusion flame combustion turbines.
Two subcategories of stationary diffusion flame combustion turbines
were established: stationary diffusion flame combustion turbines when
firing gas and when firing oil at sites where all turbines fire oil no
more than 1000 hours annually (also referred to as ``diffusion flame
gas-fired turbines''), and stationary diffusion flame combustion
turbines when firing oil at sites where all turbines fire oil more than
1000 hours annually (also referred to as ``diffusion flame oil-fired
turbines''). In a diffusion flame combustor, the fuel and air are
injected at the combustor and are mixed only by diffusion prior to
ignition. Hazardous air pollutant emissions from these turbines can be
significantly decreased with the addition of air pollution control
equipment.
Stationary combustion turbines located on the North Slope of Alaska
have been identified as a subcategory due to operating limitations and
uncertainties regarding the application of controls to these units.
There are very few of these units, and none have installed emission
controls for the reduction of HAP.
C. What are the Primary Sources of HAP Emissions and What are the
Emissions?
Combustion turbines are acknowledged as the cleanest and most
efficient method of producing electrical power. The sources of
emissions are the exhaust gases from combustion of gaseous and liquid
fuels in a stationary combustion turbine. Hazardous air pollutants that
are present in the exhaust gases from stationary combustion turbines
include formaldehyde, toluene, benzene, and acetaldehyde.
D. What are the Emission Limitations and Operating Limitations?
As the owner or operator of a new or reconstructed lean premix gas-
fired turbine, a new or reconstructed lean premix oil-fired turbine, a
new or reconstructed diffusion flame gas-fired turbine, or a new or
reconstructed diffusion flame oil-fired turbine, you must comply with
the emission limitation to reduce the concentration of formaldehyde in
the exhaust from the new or reconstructed stationary combustion turbine
to 91 parts per billion by volume (ppbv) or less, dry basis (ppbvd), at
15 percent oxygen by the effective date of the standards (or upon
startup if you start up your stationary combustion turbine after the
effective date of the standards).
[[Page 10516]]
If you comply with the emission limitation for formaldehyde
emissions and you use an oxidation catalyst emission control device,
you must continuously monitor the oxidation catalyst inlet temperature
and maintain the inlet temperature to the oxidation catalyst within the
range recommended by the catalyst manufacturer.
If you comply with the emission limitation for formaldehyde
emissions and you do not use an oxidation catalyst emission control
device, you must petition the Administrator for approval of operating
limitations or approval of no operating limitations.
E. What are the Initial Compliance Requirements?
If you operate a new or reconstructed lean premix gas-fired
turbine, a new or reconstructed lean premix oil-fired turbine, a new or
reconstructed diffusion flame gas-fired turbine, or a new or
reconstructed diffusion flame oil-fired turbine, you must conduct an
initial performance test using Test Method 320 of 40 CFR part 63,
appendix A, or ASTM D6348-03 to demonstrate that the outlet
concentration of formaldehyde is 91 ppbvd or less (corrected to 15
percent oxygen). To correct to 15 percent oxygen, dry basis, you must
measure oxygen using Method 3A or 3B of 40 CFR part 60, appendix A, and
moisture using either Method 4 of 40 CFR part 60, appendix A, Test
Method 320 of 40 CFR part 63, appendix A, or ASTM D6348-03. The initial
performance test must be conducted at high load conditions, defined as
100 percent 10 percent.
If you operate a new or reconstructed stationary combustion turbine
in one of the subcategories required to comply with an emission
limitation and use an oxidation catalyst emission control device, you
must also install a continuous parameter monitoring system (CPMS) to
continuously monitor the oxidation catalyst inlet temperature.
If you operate a new or reconstructed stationary combustion turbine
in one of the subcategories required to comply with an emission
limitation and you do not use an oxidation catalyst emission control
device, you must petition the Administrator for approval of operating
limitations or approval of no operating limitations.
If you petition the Administrator for approval of operating
limitations, your petition must include the following: (1)
Identification of the specific parameters you propose to use as
operating limitations; (2) a discussion of the relationship between
these parameters and HAP emissions, identifying how HAP emissions
change with changes in these parameters, and how limitations on these
parameters will serve to limit HAP emissions; (3) a discussion of how
you will establish the upper and/or lower values for these parameters
which will establish the limits on these parameters in the operating
limitations; (4) a discussion identifying the methods you will use to
measure and the instruments you will use to monitor these parameters,
as well as the relative accuracy and precision of these methods and
instruments; and (5) a discussion identifying the frequency and methods
for recalibrating the instruments you will use for monitoring these
parameters.
If you petition the Administrator for approval of no operating
limitations, your petition must include the following: (1)
Identification of the parameters associated with operation of the
stationary combustion turbine and any emission control device which
could change intentionally (e.g., operator adjustment, automatic
controller adjustment, etc.) or unintentionally (e.g., wear and tear,
error, etc.) on a routine basis or over time; (2) a discussion of the
relationship, if any, between changes in these parameters and changes
in HAP emissions; (3) for those parameters with a relationship to HAP
emissions, a discussion of whether establishing limitations on these
parameters would serve to limit HAP emissions; (4) for those parameters
with a relationship to HAP emissions, a discussion of how you could
establish upper and/or lower values for these parameters which would
establish limits on these parameters in operating limitations; (5) for
those parameters with a relationship to HAP emissions, a discussion
identifying the methods you could use to measure these parameters and
the instruments you could use to monitor them, as well as the relative
accuracy and precision of these methods and instruments; (6) for these
parameters, a discussion identifying the frequency and methods for
recalibrating the instruments you could use to monitor them; and, (7) a
discussion of why, from your point of view, it is infeasible,
unreasonable, or unnecessary to adopt these parameters as operating
limitations.
F. What are the Continuous Compliance Provisions?
Several general continuous compliance requirements apply to
stationary combustion turbines required to comply with the emission
limitations. You are required to comply with the emission limitations
and the operating limitations (if applicable) at all times, except
during startup, shutdown, and malfunction of your stationary combustion
turbine. You must also operate and maintain your stationary combustion
turbine, air pollution control equipment, and monitoring equipment
according to good air pollution control practices at all times,
including startup, shutdown, and malfunction. You must conduct
monitoring at all times that the stationary combustion turbine is
operating, except during periods of malfunction of the monitoring
equipment or necessary repairs and quality assurance or control
activities, such as calibration checks.
To demonstrate continuous compliance with the emission limitations,
you must conduct annual performance tests for formaldehyde. You must
conduct the annual performance tests using Test Method 320 of 40 CFR
part 63, appendix A, or ASTM D6348-03 to demonstrate that the outlet
concentration of formaldehyde is at or below 91 ppbvd of formaldehyde
(correct to 15 percent oxygen). The annual performance test must be
conducted at high load conditions, defined as 100 percent 10 percent.
If you operate a new or reconstructed stationary combustion turbine
in one of the subcategories required to comply with an emission
limitation and you use an oxidation catalyst emission control device,
you must demonstrate continuous compliance with the operating
limitations by continuously monitoring the oxidation catalyst inlet
temperature. The 4-hour rolling average of the valid data must be
within the range recommended by the catalyst manufacturer.
If you operate a new or reconstructed stationary combustion turbine
in one of the subcategories required to comply with an emission
limitation and you do not use an oxidation catalyst emission control
device, you must demonstrate continuous compliance with the operating
limitations by continuously monitoring parameters which have been
approved by the Administrator (if any).
G. What are the Notification, Recordkeeping and Reporting Requirements?
You must submit all of the applicable notifications as listed in
the NESHAP General Provisions (40 CFR part 63, subpart A), including an
initial notification, notification of performance test or evaluation,
and a notification of compliance, for each stationary combustion
turbine which must comply with the emission limitations. If your new or
reconstructed stationary
[[Page 10517]]
combustion turbine is located at a major source, has greater than 1 MW
rated peak power output, and is an emergency stationary combustion
turbine, a combustion turbine which burns landfill or digester gas
equivalent to 10 percent or more of the gross heat input on an annual
basis or where gasified MSW is used to generate 10 percent or more of
the gross heat input to the stationary combustion turbine on an annual
basis, or a stationary combustion turbine located on the North Slope of
Alaska, you must submit only an initial notification.
For each combustion turbine in one of the subcategories which is
subject to an emission limitation, you must record all of the data
necessary to determine if you are in compliance with the emission
limitation. Your records must be in a form suitable and readily
available for review. You must also keep each record for 5 years
following the date of each occurrence, measurement, maintenance,
report, or record. Records must remain on site for at least 2 years and
then can be maintained off site for the remaining 3 years.
III. Summary of Responses to Major Comments
A more detailed summary of comments and our responses can be found
in the Summary of Public Comments and Responses document, which is
available from several sources (see Addresses section).
A. Applicability
Comment: Several commenters said that the definition of affected
source should be modified to be consistent with the definition found in
Sec. 63.2 of the General Provisions.
Response: Although 40 CFR 63.2 of the General Provisions provides
that we will generally adopt a broad definition of affected source,
which includes all emission units within each subcategory which are
located within the same contiguous area, this section also provides
that we may adopt a narrower definition of affected source in instances
where we determine that the broader definition would ``create
significant administrative, practical, or implementation problems'' and
``the different definition would resolve those problems.'' This is such
an instance. Because of the way that the subcategories of combustion
turbines are defined, individual turbines can switch between
subcategories based on the fuel they are burning. We have taken some
steps in the definition of subcategories to limit the frequency of such
switching between subcategories, because we believe it could create
confusion and complicate compliance determinations. However, fuel
specific subcategories are necessary to derive a MACT floor which
appropriately considers the difference in the composition of the HAP
emitted based on the fuel used. Thus, we cannot eliminate the
possibility that individual turbines will switch subcategories. Use of
the broader definition of affected source specified by the General
Provisions would require very complex aggregate compliance
determinations, because an individual turbine could be part of one
affected source at one time and part of a different affected source at
another time. This would require that the contribution of each turbine
to total emissions for all emission units within each subcategory be
adjusted to reflect the proportionate time the unit was operating
within that subcategory. We believe such complicated compliance
determinations to be impractical and, therefore, have decided to adopt
a definition which establishes each individual combustion turbine as
the affected source.
Comment: One commenter said that the final rule should be explicit
as to whether the 1 MW capacity level for inclusion in the less than 1
MW rated peak power subcategory applies to an individual combustion
turbine or applies to the aggregate capacity of a group of combustion
turbines.
Response: We intended for the 1 MW capacity level to apply to an
individual combustion turbine, not the aggregate capacity of a group of
combustion turbines. This clarification has been made in the final
rule.
Comment: Several commenters stated that EPA should increase the 1
MW capacity threshold. Comments received included suggestions to
exclude from the rule turbines rated less than 10 MW and
recommendations to create a subcategory for units with a capacity of 25
MW or less. Some commenters said that the size applicability criteria
should be adjusted to be consistent with the MACT floor.
Response: Although 3 MW is the smallest size unit that is known to
have add-on HAP control, we feel it is appropriate to set the cutoff
for inclusion in the less than 1 MW rated peak power subcategory at 1
MW because the control technology used for 3 MW units can be
transferred to units as small as 1 MW.
Comment: Many commenters recommended that EPA provide an emission
threshold as an alternative applicability cutoff. Eight commenters
recommended that the emission threshold should be set at less than 1
tpy of formaldehyde emissions. One commenter suggested that EPA should
include a greater than 2 tpy formaldehyde applicability requirement.
Response: The basis for this comment is the Oil and Natural Gas
Production and Natural Gas Transmission and Storage NESHAP (promulgated
on June 17, 1999). In that rule, HAP emissions from process vents at
glycol dehydration units that are located at major HAP sources and from
process vents at certain area source glycol dehydration units are
required to be controlled unless the actual flowrate of natural gas in
the unit is less than 85,000 cubic meters per day (3.0 million standard
cubic feet per day), on an annual average basis, or the benzene
emissions from the unit are less than 0.9 Mg/yr (1 tpy). The 1 tpy
emission threshold in the Oil and Natural Gas Production and Natural
Gas Transmission and Storage MACT is equivalent to the smallest size
glycol dehydration unit with control of HAP emissions and is,
therefore, based on equivalence, not risk.
Comment: Multiple commenters expressed that the emission factors
presented in Table 1 of the preamble should be removed, or wording
should be added to acknowledge the use of factors from other sources.
Three commenters said that EPA should not dictate emission factors for
major source determination; owners and operators should be allowed to
determine appropriate emission factors for their facility.
Response: We agree with the commenter and have not included Table 1
from the proposal preamble in the final rule. Table 1 was intended to
simplify major source determination, e.g., facilities would not have to
develop their own emission factors. We agree that all turbines may not
fit the emissions mold as projected in Table 1. The use of the emission
factors in Table 1 was intended to be optional; we were not dictating
the use of these emission factors.
The emission factors in Table 1 of the preamble to the proposed
rule were based on emissions data from test reports that were reviewed
and accepted by EPA according to a common set of acceptance criteria.
However, we received several comments regarding the quality of the
emissions data we used and as a result, performed an extensive review
of tests used at proposal and new tests received during the comment
period. As a result of that review, revised emission factors for
stationary combustion turbines were calculated and are presented in a
memorandum included in the rule docket (OAR-2002-0060, A-95-51). That
memorandum has emission factors
[[Page 10518]]
for both high load and all load conditions. The emission standards in
the final rule are based on data for high loads.
We believe that the emission factors presented in the memorandum
provide the most accurate information on stationary combustion turbine
emission factors. However, caution should be used when using data
collected using California Air Resources Board (CARB) Method 430 or EPA
Method 0011 in determining applicability. We have used CARB 430 and EPA
Method 0011 in developing emission factors but applied a bias factor to
the data to make the emissions data comparable with emissions data
measured by Fourier Transform Infrared (FTIR).
Comment: Multiple commenters supported the creation of a
subcategory for limited use combustion turbines with a capacity
utilization of 10 percent or less. One commenter expressed the view
that the limited use subcategory should apply to all limited use
combustion turbines, not just electric power peak shaving units.
Three commenters supported the exemption for limited use units and
EPA's finding that no emission reduction should be required for these
units.
Several commenters requested that EPA increase the allowable
operating time for limited use turbines. One commenter recommended that
the 50-hour allowance for limited use be increased to 200 hours to
allow for maintenance checks. Two commenters stated that a more
appropriate cut-off is 500 hours per year, which one commenter said is
consistent with EPA policy for designating emergency engines for title
V permits and is also appropriate because year-to-year variability in
the utilization does not result in routine changes in a unit's status.
A commenter also suggested that EPA could develop a more refined
approach; for example, the cutoff for turbines greater than 10 MW could
be 200 hours per year.
One commenter said that if a 10 percent utilization is not
implemented, the testing of combustion turbines to assure the unit will
be operational when needed should be excluded from the operating limit,
because these testing operations can range from weekly testing for more
than 1 hour to several times each month.
Two commenters contended that the subcategorization of limited use
combustion turbines without controls is not protective of public
health, because these combustion turbines operate mostly in the summer
months when the public is more likely to be exposed to the emissions.
Two commenters remarked that any subcategorization of limited use
combustion turbines should include a permit requirement that these
units operate less than 876 hours per year. To lower costs for these
units, less onerous monitoring requirements such as periodic stack
tests with a temperature sensor on the catalyst could be required.
One commenter expressed the view that existing limited use
combustion turbines might be exempted from the MACT emission limits,
but new limited use combustion turbines should not be exempted. The
commenter observed that in New Jersey, limited use units generally
operate for less than 250 hours per year.
Response: The preamble for the proposed rule included a subcategory
for limited use stationary combustion turbines and defined them as
operating 50 hours or less per calendar year. We solicited comments on
creating a subcategory of limited use stationary combustion turbines
with capacity utilization of 10 percent or less and used for electric
power peak shaving. After considering all of the comments, we decided
not to include a subcategory for limited use stationary combustion
turbines in the final rule. A subcategory of limited use stationary
combustion turbines with capacity utilization of 10 percent or less and
used for electric power peak shaving was not created because these
sources are similar sources to units equipped with add-on oxidation
catalyst control, and their operation only during peak periods does not
preclude them from being equipped with add-on oxidation catalyst
control. In response to the comment regarding subcategorization of
limited use combustion turbines not being protective of public health,
our objective in subcategorizing is not to protect public health, but
to establish groups of sources which share common characteristics that
are related to the availability of potential emission control
strategies. In any case, we have not adopted a limited use subcategory,
because we determined that creation of such subcategory would not
change the nature of the required controls.
Comment: Two commenters recommended that to be consistent with most
other NESHAP, EPA should add an exemption for research and development
to the final rule.
Response: We agree that stationary combustion turbines located at a
research or laboratory facility should not be subject to the NESHAP if
research is conducted on the turbine itself and the turbine is not
being used to power other applications at the research or laboratory
facility. A definition of research or laboratory facility is included
in the final rule.
Comment: One commenter remarked that primary fuel is not defined in
the rule. The commenter noted that applying the exemption only to
turbines using landfill or digester gas as primary fuel is overly
restrictive. The commenter suggested that the exemption should be for
turbines with annual landfill and digester gas consumption of 10
percent or more of the total fuel consumption on an annual basis based
on gross heat input. Other commenters requested that the exemption for
firing landfill or digester gas be expanded to include combustion
turbines used at gasification plants.
Response: We agree that it is appropriate to provide guidelines for
the usage of landfill and digester gas. We have written the final rule
to define turbines in the landfill and digester gas subcategory as
those which burn landfill or digester gas equivalent to 10 percent or
more of the gross heat input on an annual basis. In the final rule, the
subcategory for combustion turbines firing landfill or digester gas has
been expanded to include units where gasified MSW is used to generate
10 percent or more of the gross heat input to the turbine on an annual
basis. We have specified in the final rule that new turbines in this
subcategory must daily monitor their fuel usage with a separate fuel
meter to measure the volume flow rate of each fuel. Finally, the final
rule requires new combustion turbines in this subcategory to submit
annual reports documenting the fuel flow rate of each fuel and the
heating values used to calculate and demonstrate that the percentage of
heat input provided by landfill, digester gas, or gasified MSW is
equivalent to 10 percent or more of the total fuel consumption on an
annual basis based on gross heat input.
Comment: Several commenters urged EPA to add a subcategory to cover
turbines installed north of the Arctic Circle (North Slope) and to
specify no additional control requirements for the subcategory. The
commenters stated that technologies identified for controlling HAP
emissions from stationary combustion turbines are unproven or have met
with limited success in northern Alaska above the Arctic Circle. Lean
premix combustion turbines have met with limited success on the
Alaska's North Slope. The annual average temperature above the Arctic
Circle is approximately 10F, with winter temperatures
that can drop below -50F. Turbine manufacturers have
been required to ``de-tune'' the
[[Page 10519]]
lean premix turbines to ensure the integrity of the equipment at these
cold ambient temperatures.
One of the technical issues with lean premix operation at the North
Slope is the very wide range of ambient temperatures over which the
turbine must operate. A range of -50F to
80F (130F range) is a very challenging
requirement for turbine manufacturers. They have to employ various air
bleed, inlet guide vane control, or fuel staging to allow them to
operate at the cold extremes. Sites in Canada have reported having to
tune their lean premix engines differently for the summer and winter
months. Even when temperatures drop to extremely low levels in the
lower 48 states, the duration of those low temperatures is normally
measured in hours; on the North Slope it is not uncommon for equipment
to have to endure months of severe cold. In addition to this large
range, at the colder end of the range the airflow on some turbine
models can be 40 percent higher than at the standard ISO design
conditions of 60F, creating an especially acute problem
in lean premix units. Turbine manufacturers with experience in the
Arctic do not guarantee NOX and CO levels at cold ambient
temperatures (below 0F). Therefore, lean premix turbines
that can achieve low NOX emissions typical of the lower 48
states' applications have not been demonstrated to be achievable north
of the Arctic Circle. On the North Slope, less than 0F
represents about one-half of the year.
According to the commenters, vendors of CO oxidation catalysts have
indicated that their products will perform adequately on the North
Slope, but the technology has never been tried. To date, no CO
oxidation catalyst has ever been installed on a turbine on the North
Slope. It is unknown what impacts the extreme thermal conditions of
North Slope operation will have on CO oxidation catalysts.
Response: We agree with the commenters that a subcategory should be
created for turbines installed north of the Arctic Circle to recognize
their distinct differences. There is a substantial difference in
temperature between the North Slope of Alaska and even the coldest
areas in the lower 48 states. As noted by the commenters, turbine
operators on the North Slope of Alaska have experienced problems with
operation of the turbines in lean premix mode, and turbine
manufacturers do not guarantee the performance of their turbines at the
ambient temperatures typically found north of the Arctic Circle. In
addition, no turbines on the North Slope of Alaska are equipped with
oxidation catalyst control. Therefore, a subcategory for turbines north
of the Arctic Circle has been established. The North Slope of Alaska is
defined as above the Arctic Circle (latitude 66.5
North). Stationary combustion turbines operated on the North Slope of
Alaska are not required to meet the emission limitations. However, new
or reconstructed stationary combustion turbines operated on the North
Slope of Alaska must submit an initial notification.
Comment: Two commenters expressed the view that the routine
exchange of aeroderivative turbines for routine overhaul should not
result in a facility becoming a new source. One commenter stated that
EPA should provide an exemption for temporary replacement engines
during routine rebuilds, and a mechanism to reduce the likelihood a
source would suddenly trigger new source preconstruction review/
approval and MACT requirements arising from an unexpected repair or
replacement of a stationary combustion turbine.
Response: The definition of reconstructed turbine in the proposed
rule is consistent with the General Provisions of 40 CFR part 63. If an
existing combustion turbine is refurbished to the extent that it meets
the definition of reconstruction, then it should be considered a
reconstructed source. We are not aware of any routine refurbishment for
which the fixed capital cost of the new components exceeds 50 percent
of the fixed capital cost that would be required to construct a
comparable new source.
B. Definitions
Comment: One commenter requested that the definition of lean premix
stationary combustion turbine be modified to recognize that fuel and
air mixing may be occurring in the combustor of some lean premix
combustion turbines. The definition should be modified to include these
types of stationary combustion turbines that burn a lean mixture and
thoroughly mix their fuel prior to combustion in the combustor.
Response: We have written the definition of lean premix in the
final rule to recognize that fuel and air mixing may be occurring in
the combustor of some lean premix combustion turbines.
Comment: Several commenters said that the definition of emergency
stationary combustion turbine should include operational allowances for
the periodic operation/testing to verify operational readiness. One
commenter requested that the definition be clarified, or extended to
allow for operations in anticipation of an emergency situation. Four
commenters asked for clarification as to whether loss of power that
constitutes an emergency is limited to power supplied to the facility
as a whole or includes power supplied to portions of a facility.
Response: We agree with the commenters who stated that readiness
testing should be included in the definition of emergency operation.
Accordingly, we have written the definition of emergency stationary
combustion turbine to include allowances for readiness testing in the
final rule. The routine testing and maintenance must be within limits
recommended by the turbine manufacturer or other entity such as an
insurance company. However, we disagree with the commenter who
requested the definition to include operations in anticipation of an
emergency situation. Exempt operations will be limited to emergency
situations only. We agree that loss of power can include power supplied
to portions of a facility, and we have, therefore, written the
definition of stationary emergency combustion turbine in the final rule
to make this clear.
Comment: Several commenters recommended that the definition of
``stationary combustion turbine'' include all appropriate associated
equipment.
Response: We agree with the commenters' suggestions and have
written the definition of stationary combustion turbines in the final
rule to reflect appropriate comments. The definition of a stationary
combustion turbine does not include emissions control equipment.
Comment: One commenter expressed support for the definition of
major source except that the phrase ``except when they are on the same
surface site'' should be removed from the combustion turbine major
source definition. This phrase is not present in the 40 CFR part 63,
subpart HH, major source definition that is the template for the
combustion turbine MACT major source definition. Section 112(n)(4) of
the CAA requires that wells and associated equipment not be aggregated
even within the same surface site except as provided in the combustion
turbine MACT major source definition. In the combustion turbine MACT
major source definition, the phrase ``storage vessel with flash
emissions potential'' should be changed to ``storage vessel with the
potential for flash emissions'' to conform to the 40 CFR part 63,
subpart HH, definition.
The commenter also stated that the General Provision major source
[[Page 10520]]
definition presented in the combustion turbine MACT is different from
those found in the definition of major source in the NESHAP from Oil
and Natural Gas Production Facilities (40 CFR 63.761). The significance
of this difference is that sources that are area sources under subpart
HH could possibly be rendered ``major sources'' under the combustion
turbine MACT. The EPA should acknowledge this possibility in the
preamble to the final rule and clearly state that this does not change
the source's status under subpart HH or any other MACT. Another
commenter recommended that the preamble clarify that the definition of
major source in the combustion turbine MACT does not alter the
definition of major source in subpart HH, and, therefore, does not
affect subpart HH applicability.
Response: We agree with the commenters and have written the major
source definition in the final rule to reflect appropriate comment. We
have acknowledged in the preamble to the final rule that the definition
of major source in the final rule may be different from those found in
other rules. However, this does not alter the definition of major
source in other rules, and, therefore, does not affect the Oil and
Natural Gas Production Facilities NESHAP (subpart HH of 40 CFR part 63)
or any other rule applicability.
Comment: One commenter observed that landfill and digester gas are
defined in the proposed rule as being formed through anaerobic
decomposition, which is usually but not always the case.
Response: We agree with the commenter that landfill and digester
gas are not always formed only through anaerobic decomposition. As a
result, we have written the definition of landfill and digester gas in
the final rule acknowledging that these gases are usually formed
through anaerobic decomposition, but not always by inserting the word
``typically'' in front of ``formed'' in both definitions.
C. Dates
Comment: Two commenters stated that immediate compliance is
unrealistic for new and reconstructed turbines and recommended a 1-year
compliance timeframe. Other commenters recommended that the final rule
allow 1 year to conduct the initial performance test, rather than the
180 days provided by the 40 CFR part 63, General Provisions.
Response: Immediate compliance is appropriate for new or
reconstructed turbines and is consistent with the General Provisions of
40 CFR part 63. Sources are required to install the proper equipment
and meet the applicable emission limitations on startup. However, we
allow sources 180 days to demonstrate compliance. We feel that 180 days
is sufficient time to conduct the initial performance test, consistent
with the General Provisions. Sources have the option to petition for
additional time if necessary.
Comment: One commenter requested that EPA allow a facility with
identical combustion turbines to conduct performance tests on only one
of the units to demonstrate compliance with the emission limits for all
of the identical units.
Response: We are not allowing facilities with identical combustion
turbines to conduct performance tests on only one of the units to
demonstrate compliance with the emission limits for all of the
identical units because not all apparently identical facilities produce
the same emissions. We have turned down many similar requests and have
asked owners and operators to run stack tests on all individual units.
Comment: Two commenters requested that the rule provide 1 year for
initial notification of MACT applicability, as in the Oil and Natural
Gas Production and the Natural Gas Transmission and Storage MACT,
instead of 120 days.
Response: We do not agree that 1 year is necessary for initial
notification of MACT applicability. An initial notification is not a
time consuming activity.
D. MACT
Comment: Three commenters took issue with the MACT floor for new
diffusion flame stationary combustion turbines. The commenters stated
that no formaldehyde emissions data or oxidation catalyst control
efficiency data were available to EPA to support setting the MACT floor
for new diffusion flame stationary combustion turbines; newer models of
turbines in the diffusion flame category should be evaluated to
identify the best-performing unit.
Response: At proposal, we had limited emissions data for stationary
combustion turbines, including one test for a diffusion flame turbine
with add-on HAP emission control, and we requested HAP emissions test
data from stationary combustion turbines. We received new emissions
data for diffusion flame turbines during the comment period, including
an additional formaldehyde test on a diffusion flame unit equipped with
add-on HAP emissions control. The new data also include several tests
conducted using FTIR, which is regarded as the most accurate
measurement method for formaldehyde for stationary combustion turbines.
Thus, the data set has been significantly improved, both quantitatively
and qualitatively, and we feel that the data set is sufficient to
identify the best-performing unit.
Based on comments and information received during the public
comment period, the diffusion flame subcategory was divided further
into subcategories for diffusion flame combustion turbines when firing
gas and when firing oil at sites where all turbines fire oil for no
more than 1000 hours annually (``diffusion flame gas-fired turbines'')
and for diffusion flame combustion turbines when firing oil at sites
where all turbines fire oil more than 1000 hours annually (``diffusion
flame oil-fired turbines'').
In addition, based on information received during the public
comment period indicating that oxidation catalysts are in use on some
existing diffusion flame combustion turbines, we reevaluated the MACT
floor for new turbines in each of the diffusion flame subcategories.
Comment: One commenter contended that the MACT floor for existing
diffusion flame is unlawful because EPA did not identify the best
performing sources or determine the emission levels they are achieving;
EPA merely considered whether or not they are equipped with a catalyst.
The commenter stated that whether or not the relevant best sources are
equipped with control equipment, they are achieving some emission
level, and EPA must determine the average emission level they are
achieving and set floors at that level.
Response: We agree with the commenter that all factors which might
control HAP emissions must be considered in making a floor
determination for each subcategory, and that this analysis cannot be
properly limited to add-on controls. However, we disagree that it must
express the floor as a quantitative emission level in those instances
where the source on which the floor determination is based has not
adopted or implemented any measure that would reduce emissions. In this
instance, we decided to subcategorize within diffusion flame combustion
turbines based on the fuel which is used, because the composition of
HAP emissions differs materially based on whether gas or oil is used.
We then determined for each subcategory of diffusion flame combustion
turbines that emissions of each HAP are relatively homogenous across
that subcategory, and that there are not any
[[Page 10521]]
adjustments of the turbines or other operational modifications except
for the use of add-on controls which would be effective in reducing HAP
emissions. Since the source on which the floor for existing sources in
each subcategory of diffusion flame turbines is based has not installed
such add-on controls, we determined that the MACT floor for each such
subcategory requires no emission reductions. We have also established
fuel-based subcategories within lean premix combustion turbines, and
have made a comparable determination that the MACT floor for existing
sources within each of these subcategories requires no emission
reductions.
Comment: One commenter said that the MACT floor for new diffusion
flame units is unlawful because EPA did not identify the best-
performing diffusion flame combustion turbine and the floor does not
reflect what that source achieved in practice. According to the
commenter, EPA ignored other factors that affect a source's performance
(fuel, design, age, maintenance, operator training, skill and care,
differences in effectiveness of catalysts). The performance of all
sources using an oxidation catalyst is not the same and cannot possibly
reflect the performance of the single best source.
Response: We agree with the commenter that the standard for new
sources within each subcategory must be based on the emission levels
achieved in practice by the best controlled similar source. However, we
think that the performance in reducing emissions by the best controlled
source will not be uniform, and that it would be inappropriate to
establish a standard which could not be consistently met even by the
source upon which the standard is based. We, therefore, believe that
there must be some allowance made for the intrinsic variability in the
effectiveness of controls in the standard we establish. We do not think
that the performance of oxidation catalysts differs as much from one
turbine to the next as suggested by the commenter, and we believe that
the emission control levels achieved in practice by catalysts on
differing turbines is one factor we may appropriately consider in
evaluating the variability in emission control levels which is
intrinsic to catalyst operation.
Comment: One commenter observed that EPA stated that it considered
fuel switching but could not find a less HAP emitting fuel. The EPA's
own data show that combustion turbines burning fuel oil have higher
benzene and xylene emissions than combustion turbines firing natural
gas or landfill gas. Had EPA tested other HAP, it would likely have
found that fuel oil produces higher levels of those HAP as well. The
EPA has already found the entire diesel exhaust stream to be hazardous.
Response: We agree with the commenter that the composition of HAP
emissions are different for combustion turbines firing natural gas and
combustion turbines firing oil. We have evaluated both the data we had
prior to proposal and the data received since proposal; the test data
support the conclusion that HAP emissions are different for different
fuels for stationary diffusion flame units. Uncontrolled formaldehyde
emissions are in general lower as a result of the combustion of
distillate oil than for natural gas. Other differences in emissions
between natural gas and distillate oil include higher levels of
pollutants such as PAH and metals for stationary combustion turbines
burning distillate oil.
We proposed one subcategory for combustion turbines using lean
premix technology and another subcategory for combustion turbines using
diffusion flame technology. However, in recognition of the clear
differences we found in the composition of HAP emissions depending on
the fuel that is used, we have determined that it is appropriate to
subcategorize further based on fuel use. In devising appropriate
subcategories based on fuel use, we need to consider that many
combustion turbines are configured both to use natural gas and
distillate oil. These dual fuel units typically burn natural gas as
their primary fuel, and only utilize distillate oil as a backup. To
limit the frequency of switching between subcategories caused by
limited usage of a backup fuel, we have defined the gas subcategories
in a manner which permits combustion turbines that fire gas to remain
in the gas subcategory if all turbines at the site in question fire oil
no more than a total of 1000 hours during the calendar year.
Comment: Several commenters took issue with the methodology and
data used to set the MACT floors for lean premix units. Two commenters
contended that EPA's determination of the floor for existing lean
premix turbines is fundamentally flawed, and that reliance on a single
data point and the assumptions made to compensate for the inherent
error and variability is not appropriate. It was suggested that EPA
must obtain additional information before it can set a floor.
Two commenters stated that data from all five combustion turbines
should be used to set the MACT floor for existing lean premix turbines.
One commenter determined that the formaldehyde limit should be 219 ppb
if EPA declines to set the floor as no emission reduction.
Several commenters remarked than the MACT floor for new and
existing lean premix turbines does not reflect a reasonable estimate of
formaldehyde emissions achieved in practice by the best-performing
source; EPA should adjust the MACT floor to reflect formaldehyde
emissions reasonably expected over the operating range of the best-
performing lean premix turbine. One commenter observed that EPA's use
of the performance test of one ``best'' lean premix unit is not
statistically viable and does not meet the statutory requirement for
setting the MACT floor.
Two commenters said that EPA's emission standard for lean premix
combustion turbines is unlawful and EPA should establish a ``no
control'' emission limitation. It was also stated that EPA did not
determine that the best performers in the subcategory were
``controlling'' their emissions in a duplicable manner. They stated
that EPA improperly set the floor for the existing lean premix
subcategory; EPA based the floor on the performance of the best source
for which it had data, instead of basing it on the average emission
limitation of the five sources for which it had data. They also stated
that all of the variability that either the best performers will
experience or that will affect the attainability of emissions had not
been considered and suggested that EPA consider the normal turbine
variations based on time, fuel, location, weather, and the
repeatability of testing and monitoring methods.
Response: As previously discussed, we had limited emissions data at
proposal for stationary combustion turbines. We had five tests for
formaldehyde emissions for lean premix combustion turbines, none of
which were on lean premix units with add-on HAP emission control. We
received new emissions data for lean premix turbines, including two
formaldehyde tests on a lean premix unit equipped with add-on HAP
emissions control. The new data also include several tests conducted
using FTIR, which is regarded as the most accurate measurement method
for formaldehyde for stationary combustion turbines. Thus, the data set
has been significantly improved, both quantitatively and qualitatively,
and EPA believes that the data set is sufficient to identify the best-
performing unit.
Also, as discussed previously, we decided that it is appropriate to
subcategorize based on fuel within the subcategories for diffusion
flame and lean premix combustion turbines. We have established
subcategories for lean
[[Page 10522]]
premix combustion turbines when firing gas and when firing oil at sites
where all turbines fire oil for no more than 1000 hours annually
(``lean premix gas-fired turbines''), and for lean premix combustion
turbines when firing oil at sites where all turbines fire oil more than
1000 hours annually (``lean premix oil-fired turbines'').
As a result of comments and the new data submitted post-proposal,
we also have reevaluated the MACT floor for both existing and new
turbines in each of the lean premix subcategories.
Comment: One commenter said that the MACT floor for existing lean
premix combustion turbines is unlawful. The floor (formaldehyde) is at
a level far worse than the emission levels achieved by the best source.
The 95 percent reduction standard is unlawful because it does not even
purport to reflect the actual emission levels achieved by the relevant
best sources. The commenter also stated that CO is not a valid
surrogate.
Response: We reevaluated the MACT floor for existing gas-fired and
oil-fired LPC units as a result of comments and the new data submitted
post-proposal. We do not agree that CO reduction is not a valid
surrogate for HAP reduction, however, the alternative CO emission
limitation has been removed from the final rule due to CO measurement
difficulties. Thus, the commenter's concerns are moot. We have
determined that formaldehyde is an appropriate and valid surrogate for
each of the organic HAP that can be controlled by a catalyst, and that
the standard for such organic HAP can be reasonably expressed in terms
of formaldehyde emissions measured after exiting any control device.
Comment: One commenter stated that the MACT floor for new lean
premix units does not reflect the actual performance of the single best
source.
Response: As explained above, we believe that we must accommodate
intrinsic variability in performance when setting a standard which is
based on the performance of the best controlled similar source. It
would make no sense to adopt a standard based on the best controlled
source which could not be consistently met even by that source.
Comment: One commenter remarked that for MACT, EPA's rejection of
potential control technologies that might be applied, including wet
scrubbers, dry scrubbers, and activated carbon, without even
considering them is unlawful, and that EPA's argument that a greater
degree of reduction could not be achieved through the use of clean
fuels is unlawful.
Response: We agree with the commenter that the effect of the choice
of natural gas or fuel oil on the composition of HAP emissions is
significant, and we have, therefore, subcategorized further within both
lean premix and diffusion flame turbines based on which of these fuels
is used. We are not aware of any data indicating that HAP emissions
could be consistently reduced by selection of particular clean fuels
within these general fuel groups. As for the other novel emission
control technologies to which the commenter refers, we do not believe
that these technologies are in use on any combustion turbine and we do
not consider any sources utilizing such controls to be similar sources.
Moreover, we are unable based on available information to determine
that these technologies would be both efficacious and cost effective in
reducing HAP emissions from combustion turbines.
Comment: One commenter remarked that for existing emergency,
limited use, landfill or digester gas fired, and less than 1 MW units,
EPA did not set a floor that reflects the emission levels that the best
performing sources actually achieved. The EPA has not identified the
relevant best performing sources and has not determined the average
emission limitation achieved by such sources, therefore, EPA's floors
for these sources are unlawful.
Response: We have not decided to establish a limited use
subcategory. For the emergency, landfill or digester gas fired, and
less than 1 MW subcategories, we have not identified any adjustments or
other operational modifications that would materially reduce emissions
by these units and we have determined that no add-on controls are
presently in use. In these circumstances, we believe that we have
appropriately established the floors for these sources as no emission
reduction.
Comment: One commenter said that for new emergency, limited use,
landfill or digester gas fired, and less than 1 MW units, the floor is
unlawful because EPA did not identify the single best controlled source
in any of these subcategories and did not set floors reflecting such
source's actual performance.
Response: As noted above, we have not decided to establish a
limited use subcategory. For the emergency, landfill or digester gas
fired, and less than 1 MW subcategories, we have not identified any
adjustments or operational modifications that would materially reduce
emissions by these units and we have determined that no add-on controls
are presently in use. We also have determined because of the specific
characteristics of turbines in these subcategories that the turbines in
other subcategories that utilize add-on controls are not similar
sources. In these circumstances, we believe that we have appropriately
determined that the new source MACT floor for these subcategories
should also be no emission reduction.
Comment: One commenter contended that EPA's rejection of beyond the
floor standards for new emergency, limited use, landfill or digester
gas fired, and less than 1 MW units is arbitrary and capricious. The
EPA does not state the cost of applying any control technology or
indicate the quantity of the HAP that would be reduced.
Response: We believe that the record includes analysis
demonstrating that it is not cost effective to require HAP controls for
turbines in instances where no similar source has installed such
controls.
Comment: One commenter said that EPA's proposal is unlawful because
EPA must set standards for each listed HAP. Oxidation catalyst control
devices do not control many of the HAP that combustion turbines emit,
for example metals.
Response: We do not agree that it is required to establish a
discrete standard for each listed HAP. However, we do agree that each
listed HAP must be separately considered by EPA, both in determining
the MACT floors and in establishing the emission standards for each
subcategory. If emissions of a particular HAP are relatively homogenous
for a particular subcategory, and there are no adjustments or
operational modifications except for add-on controls which would reduce
emissions of that HAP, the MACT floor and the emission standard for
that HAP may be expressed as a level of emission reduction
corresponding to the efficacy of add-on controls. Moreover, if the data
demonstrate that control of emissions of a particular HAP is a suitable
surrogate for control of emissions of a group of listed HAP, we may
appropriately set the standard in terms of a level of emission
reduction or an emission level for that particular HAP.
In establishing new source standards for certain subcategories, we
determined that formaldehyde is an appropriate surrogate for the other
organic HAP which are also controlled by an oxidation catalyst. While
use of an oxidation catalyst does not control the metallic HAP which
are emitted by turbines burning distillate oil, there are no combustion
turbines or similar sources utilizing other technologies to
[[Page 10523]]
control metallic HAP. Moreover, we do not believe it would be practical
or cost effective to require control of these metallic HAP and,
therefore, the floor and the standard for each metallic HAP was
appropriately set at no emission reduction.
Comment: One commenter noted that EPA's floors must reflect the
average emission levels achieved by the relevant best sources. Thus,
even if some of the relevant best sources are not using any control
device, the agency must average their performance with that of the
relevant best sources that are using a control device. That some of the
relevant best performers are not using an end-of-stack control
technology does not allow EPA to discount the performance of other best
performers that are using such technology.
Response: We do not agree with the premise of this commenter that
the existing source MACT floor (the average emission limitation
achieved by the best performing 12 percent of existing sources or the
best performing five existing sources in subcategories with fewer than
30 sources) must be calculated by determining the arithmetic average of
the emission limitations achieved individually by each of these
sources. We have consistently construed the statute to permit us to
determine the average emission limitation by selecting the median
facility among the best performing 12 percent or five existing sources.
We think this well-established construction of the statute is
reasonable, because an arithmetic average will quite often not coincide
with the level of emission reduction that has been achieved in practice
by any real facility. We do not think it is appropriate to establish an
existing source MACT floor which may not be achievable by most of the
sources from which it was derived. Nor do we think it is required to
set a standard which is less stringent than most of the sources from
which it is derived are achieving. Use of the emission limitation
achieved by the median facility avoids these problems.
E. Emission Limitations
Comment: Many commenters stated that the final rule should only
apply emission standards to the load range represented by the emissions
data used to determine emission limitations.
Response: The emission standards are based on data from testing at
high loads (90 percent and greater). To address the concerns expressed
by the commenters about the emission standards being applicable at full
load only, the final rule specifies that the performance test must be
conducted at high load conditions, defined as 100 percent 10 percent.
Comment: Many commenters took issue with the data used to set the
formaldehyde emission limitation. The commenters noted that the test
reports used to set the limit used two different test methods and that
the limit was based on only five data points and, therefore, does not
reflect a level of performance that is achievable for all sources. One
commenter said that EPA has not provided enough data to know
definitively what the standard should be. Another commenter stated that
EPA must obtain additional information before it can set a floor.
The commenters also had concerns about possible errors in the test
reports that are the source of the emissions data used to set the
formaldehyde emission limitation. One commenter said that close
examination of the five reports uncovers questions regarding the actual
test procedures, comparability, data reduction and data reporting that
should be revisited before finalizing the formaldehyde concentration
limit. They stated that all five reports appear to have calculation
errors and/or other data quality issues that significantly affect the
reported formaldehyde concentration, the comparability of the results
because different test methods were used, and/or uncertainty associated
with the average result. One commenter also reviewed the five tests
used to set the standard and found that all of the five tests used do
not present valid quantitative results; and that data from these tests
may not be used to establish a quantitative emission standard for
formaldehyde emissions from lean premix combustion turbines.
One commenter said that CARB 430 may report anomalously low
formaldehyde emissions; therefore, the standard may be too stringent
and unachievable in practice. Two commenters questioned whether the
CARB 430 data used to develop the standard followed CARB method
requirements. One commenter believed that the results from all tests
used to determine the MACT floor should be recalculated using CARB 430
procedures so the data can be justifiably compared and that results
should also be recalculated using the American Society of Mechanical
Engineers measurement uncertainty analysis procedure. The EPA should
then use these results for establishing the formaldehyde concentration
limit. The commenter estimated that an enforceable formaldehyde
concentration limit should be in the range of approximately 100 to 500
ppb.
One commenter said that a single emission test does not fully
reflect the variability that will be seen by the best performing source
employing any technology. The EPA should properly assess variability
that may be experienced by the best performing sources under the worst
foreseeable conditions that are expected to recur. Emission testing
conducted by the commenter in conjunction with the Gas Turbine
Institute indicates that 43 ppb is not achievable for small industrial
and aeroderivative turbines.
Several commenters suggested a revised level for the emission
limitation. One commenter said that EPA must revise the limit upward to
at least 63 ppb. Two commenters stated that additional formaldehyde
data suggests that EPA should consider setting the emission standard to
90 ppbvd given the tremendous variability in the few measurements that
are available. One commenter submitted a summary table of data for nine
tests conducted on lean premix combustion turbines. The test results
show a variability between high and low loads of 34 percent; also, six
out of nine tests were above 43 ppb.
Response: As a result of comments received during the comment
period, we performed an extensive review of tests used at proposal and
new tests received during the comment period. A screening analysis of
the formaldehyde test data for diffusion flame combustor turbines was
conducted. Tests conducted using CARB 430 were evaluated due to the
CARB advisory issued April 28, 2000, which stated that formaldehyde
data measured by CARB 430 where the NOX emissions were
greater than 50 ppm should be flagged as non-quantitative. Tests where
the NOX emissions were greater than 50 ppm, or tests where
the NOX levels were unknown, were excluded from our
analysis. Most of the diffusion flame tests in the EPA's combustion
turbine emissions database were unable to pass the screening. The tests
unable to pass the screening were not equipped with add-on control for
the reduction of HAP.
The remaining test reports were further analyzed and reviewed to
ensure the methods were used correctly in calculating and reporting
formaldehyde concentrations and to check that proper quality assurance
(QA)/quality control (QC) procedures were followed. A number of errors
were found in the test reports where CARB 430 was used to quantify
formaldehyde concentrations. In several instances, the CARB 430
reporting protocol was not followed. If the analytical concentration is
less than five times the average field blank, then CARB 430 uses five
times the field
[[Page 10524]]
blank as the reported result to correct for interferences or
contaminants that can react with the formaldehyde or
dinitrophenylhydrazine to yield negative bias. However, many test
reports did not report formaldehyde concentrations in this fashion. The
formaldehyde concentrations were, therefore, recalculated where the
CARB 430 reporting protocol was not followed correctly.
No errors were found in test reports which used FTIR to measure
formaldehyde concentrations in the stationary combustion turbine
exhaust. The reported formaldehyde concentrations were representative
of stationary combustion turbines and the measured QA/QC parameters
were within acceptable limits as set in the method.
We agree that CARB 430 generally understates the formaldehyde
concentration in the exhaust gas from stationary combustion turbines.
Since EPA Method 0011 is a similar method to CARB 430, it is believed
that Method 0011 also understates the emissions of formaldehyde. We
feel that FTIR is a more accurate and reliable method than CARB 430.
Several test reports were received during the comment period on recent
testing on small lean premix combustion turbines which used both CARB
430 and FTIR to measure formaldehyde emissions. An analysis was
conducted to correlate formaldehyde concentrations measured by CARB 430
and formaldehyde concentrations measured by FTIR. A linear regression
was performed on the CARB 430 and FTIR formaldehyde data from these
tests which gave a slope of 1.667 with a correlation coefficient of
0.561. Therefore, we concluded that CARB 430 formaldehyde results are
on average 1.7 times lower than FTIR formaldehyde results. To account
for the differences in the methods, a bias factor of 1.7 was applied to
the CARB 430 and Method 0011 formaldehyde emissions data to make these
data comparable to FTIR.
As a result of a complete data review, including emissions data we
had at proposal and new emissions data we received during the comment
period, we currently have a very different data set as compared to what
we had at proposal. For example, the amount of data for lean premix
units increased, while the amount of data for diffusion flame units
decreased. As discussed previously, the new data set was used to
determine the MACT floors. For new lean premix gas-fired turbines and
new lean premix oil-fired turbines, a formaldehyde emission limitation
of 91 ppb was established for the MACT floor. It is felt that this
emission limitation will be achievable for both small and large size
combustion turbines. We considered establishing separate subcategories
by size but found that there was little difference in emissions among
the best performing small and large units. The best performing large
lean premix unit was controlled by an oxidation catalyst, and EPA had
data from two separate tests of this turbine. Formaldehyde emissions
were measured at 19 and 91 ppb. The best performing small lean premix
unit (less than 25 MW) had uncontrolled formaldehyde emissions of 68
ppb, which is within the range of emissions for the large lean premix
unit.
We have adequately considered the variability in emissions by the
best performing source. We have emissions data for two tests for the
best performing turbine in the lean premix gas-fired turbine
subcategory; the formaldehyde emissions varied by a factor of five
between the two tests. Since both tests were performed under similar
conditions but at different times, they represent the variability of
the best performing unit. The MACT floor for this subcategory was set
based on the higher formaldehyde measurement, thus the variability of
the best performing unit has been accounted for. Similar variability
factors were applied for the other subcategories. This is explained
further in section III.E.
F. Monitoring, Recordkeeping, and Reporting
Comment: Multiple commenters requested that the CO continuous
emission monitoring system (CEMS) requirement be removed and periodic
testing/parametric monitoring be adopted. Some commenters cited the
cost burden of a CEMS, and others noted that a requirement for CO CEMS
imposes an excessive cost burden for smaller turbines. One commenter
also noted that CEMS have typically not been required on small turbines
and personnel would not be familiar with CEMS operation and
maintenance, resulting in increased capital and operating costs.
Furthermore, one commenter felt that there would not be significant
emissions reduction for the use of CEMS compared to the use of inlet
temperature monitoring and periodic emission testing, the requirement
is inconsistent with previous EPA decisions on monitoring, and there
are deficiencies in the test methods and performance protocols. One
commenter questioned whether the low measurements can be made
accurately and reliably on a continuous basis without jeopardizing the
flexibility of facility operations.
Many commenters recommended alternatives to the CO CEMS
requirement. One commenter suggested the option of monitoring
compliance with a one-time performance test for CO. One commenter said
that an option could be reliance on a Federal CO permit limit combined
with periodic CO stack testing. If the permitted CO limit is relatively
high, compliance with the formaldehyde limit at that level could first
be determined using an initial formaldehyde test. If the CO limits/
concentration are low, initial formaldehyde testing should not be
necessary. The commenter recommended that EPA establish a default
minimum compliance demonstration at 5 parts per million (ppm). One
commenter recommended that EPA evaluate periodic stack tests, conducted
on the same schedule as relative accuracy test audit (RATA) testing as
an alternative to CEMS. At a minimum, this approach should be pursued
for units with oxidation catalyst systems that would qualify as peaking
units under the Acid Rain Program and are not otherwise required to
conduct emissions monitoring for CO or other pollutants.
One commenter said that a more workable solution would be to
measure downstream CO, but only if a CEMS is already required for
NOX. A catalyst efficiency test could be performed
periodically to confirm continued reduction efficiency (an option to
perform this check with portable analyzer should be included). One
commenter said that if EPA includes an option to monitor CO emissions
using CPMS rather than CO CEMS, a requirement to replace a catalyst bed
when the pressure drop increases by more than 2 inches of water from
the drop measured during the initial performance test may not be
appropriate. Particular vendors are better able to specify the
conditions under which catalyst replacement is warranted.
Response: In the preamble for the proposed rule, we solicited
comments on the performance capabilities of a state-of-the-art CO CEMS
and its ability to measure the low concentrations of CO in the exhaust
of a stationary combustion turbine following an oxidation catalyst
control device. In general, commenters did not support CO CEMS, stating
that existing CO CEMS technology and EPA performance criteria are not
adequate to reliably and accurately measure trace levels of CO. Due to
the CO measurement difficulties, EPA has decided not to include the CO
[[Page 10525]]
emission reduction limitation in the final rule.
Comment: One commenter remarked that subsequent performance testing
(suggest no more frequent than annually) is needed for units meeting
the formaldehyde limit, and that there should also be some methodology
for the demonstration of continuous compliance.
Response: We agree with the commenter that subsequent performance
testing is needed for units meeting the formaldehyde limit. The final
rule includes a requirement for annual performance testing for units
meeting the formaldehyde limit and designated requirements for
continuous compliance. For sources equipped with oxidation catalyst
control, continuous compliance will be demonstrated by continuously
monitoring the inlet temperature to the catalyst and maintaining the
inlet temperature within the range suggested by the catalyst
manufacturer. Sources that are not equipped with oxidation catalyst
control must petition the Administrator for approval of operating
limitations or approval of no operating limitations.
Comment: One commenter said that EPA should allow facilities to use
existing test data to demonstrate compliance with the emission
limitation if the test was conducted using the same methods specified
in the rule and no process changes have been made since the test, or it
can be demonstrated that the results of the performance test reliably
demonstrate compliance despite process changes.
Response: Since there are no emission limitation requirements for
existing sources in the final rule, we expect that few facilities will
have existing test data to demonstrate compliance. Facilities that came
online after the proposal would be the only sources that may have
conducted emissions testing prior to the stack testing requirements of
the final rule, and we will allow facilities to use existing test data
to demonstrate initial compliance with the emission limitation if the
data is of good quality and is no older than 2 years. (After the
initial compliance demonstration, facilities must then begin to follow
the annual compliance test schedule.) The facility must petition the
Administrator for approval and demonstrate that the tests were
conducted using the same test methods specified in the subpart, the
test method procedures were correctly followed, no process or equipment
changes have been made since the test, and the data are of good quality
and less than 2 years old. This has been specified in the final rule.
G. Test Methods
Comment: Several commenters expressed concern regarding the
accuracy and precision of CARB Method 430 at levels commensurate with
the proposed standard. Two commenters noted that CARB Method 430 is
susceptible to interferences. One commenter said that sample loss and
measurement uncertainties can contribute to large measurement
variability. Another commenter contended that CARB Method 430 is an
indirect measurement method and is inferior to Method 320. This
commenter also said that CARB Method 430 cannot give realistic results.
Response: New information provided during the public comment period
where CARB 430 and FTIR were concurrently tested showed that CARB 430
using the CARB reporting protocol is biased low by a factor of 1.7
compared to FTIR. Therefore, we agree with the commenters' concerns
regarding the accuracy of CARB Method 430 and that it is an indirect
measurement method, however, EPA disagrees that CARB Method 430 cannot
give realistic results. In some cases, we believe that CARB Method 430
can provide realistic results. However, we also agree that FTIR would
be the better compliance method. Therefore, we have specified Method
320 and ASTM D6348-03 as the compliance procedures in the final rule.
Comment: Several issues were raised in the comments received
regarding EPA Method 0011. One commenter did not support the use of EPA
Method 0011 for combustion turbines because there is no need for
isokinetic sampling in combustion turbine stacks, compared to CARB
Method 430 the field procedure is more complex, the potential for
chronic field contamination is much greater, the QA/QC procedures are
vastly inferior, the data reporting procedures especially with respect
to blanks are more vague, and the method does not have sufficient
sensitivity for demonstrating compliance with the proposed formaldehyde
limit.
Response: We agree with the commenters that the method has many
shortcomings and limited application opportunities for use in measuring
formaldehyde emissions from stationary combustion turbines.
Accordingly, we are not including EPA Method 0011 in the final rule.
Both EPA Method 0011 and CARB Method 430 can be requested on a case-by-
case basis as part of EPA's alternative method review process.
Comment: Several commenters did not support Method 323. The
commenters said that the method should not be used for measuring very
low concentrations of formaldehyde. The minimum detection levels of the
method are not suitable for the emission standards. Two commenters also
noted that the method has not been validated or demonstrated for use on
combustion turbines with low ppb range formaldehyde emissions.
Response: We agree with commenters that Method 323 should not be
used for measuring low concentrations of formaldehyde from combustion
turbines. Therefore, we are not including Method 323 in the final rule.
Comment: Numerous commenters said that CO CEMS cannot reliably
measure trace level CO concentrations and 95 percent CO reduction. One
commenter remarked that EPA provides no information to show that CEMS
are available to accurately measure low CO concentrations, and the use
of CO CEMS for low levels is well beyond the scope of current 40 CFR
part 60 CEMS performance standards. Also, vendor claims for CO CEMS and
CO instrumental analyzers, unless accompanied by emissions test data
obtained under known and controlled conditions applicable to the
subject source type, should not be considered adequate proof of
availability and performance.
Response: We agree that existing CO CEMS technology and EPA
performance criteria are not adequate to reliably and accurately
measure trace levels of CO. The American Society for Testing and
Materials (ASTM) is currently trying to address this issue, with
participation by EPA. The requirement for CO CEMS has not been included
in the final rule.
Comment: Three commenters sought an allowance for site specific
emission limits where duct burners are utilized and the formaldehyde
limit applies. Three commenters recommended that facilities should be
allowed to either accept the formaldehyde limit at the stack with the
duct burner in operation, or be allowed to petition the EPA for an
alternate (higher) formaldehyde limit for the combined turbine/duct
burner co-firing.
Response: We have included the commenters' suggestions that
facilities be allowed to accept the formaldehyde limit at the stack
with the duct burner in operation in the final rule; however, it is not
necessary to specify in the final rule that affected sources are
allowed to petition EPA for an alternate formaldehyde limit.
H. Risk-Based Approaches
The preamble to the proposed rule requested comment on whether
there might be further ways to structure the
[[Page 10526]]
final rule to focus on the facilities which pose significant risks and
avoid the imposition of high costs on facilities that pose little risk
to public health and the environment. Specifically, we requested
comment on the technical and legal viability of three risk-based
approaches: an applicability cutoff for threshold pollutants under the
authority of CAA section 112(d)(4), subcategorization and delisting
under the authority of CAA section 112(c)(1) and (9), and, a
concentration-based applicability threshold.\1\
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\1\ See 68 FR 1276 (January 9, 2003) (Plywood and Composite Wood
Products Proposed NESHAP) and docket number A-98-44 (White Papers
submitted to EPA outlining the risk-based approaches).
---------------------------------------------------------------------------
We indicated that we would evaluate all comments before determining
whether either approach would be included in the final rule. Numerous
commenters submitted detailed comments on these risk-based approaches.
These comments are summarized in the Response-to-Comments document (see
SUPPLEMENTARY INFORMATION section).
Based on our consideration of the comments received and other
factors, we have decided not to include the risk-based approaches in
today's final rule. The risk-based approaches described in the proposed
rule and addressed in the comments we received raise a number of
complex issues. In addition, we must issue the final rule expeditiously
because the statutory deadline for promulgation has passed, and we have
agreed to a binding schedule in a consent decree entered in Sierra Club
v. Whitman, Civil Action No. 1:01CV01537 (D.D.C.). Given the range of
issues raised by the risk-based approaches and the need to promulgate a
final rule expeditiously, we believe that it is appropriate not to
include any risk-based approaches in today's final rule.
I. Other
Comment: Two commenters remarked that EPA's declaration that diesel
fired turbines cannot be operated in the lean premix mode is a
misstatement. While some manufacturers, on some models, only offer
liquid fuel capability in diffusion flame mode, other manufacturers
have offered the dual fuel option on lean premix turbines since the
mid-1990's. One commenter stated that the standard should be modified
because of the dual fuel capability of combustion turbines. The
commenter noted that EPA has no data to represent lean premix liquid
fuel operation and, therefore, cannot determine an appropriate
standard.
Response: At the time the NESHAP were proposed, we were not aware
of the availability of diesel fired turbines that operated in the lean
premix mode. We have since contacted several turbine manufacturers in
an attempt to obtain more information about these units, and two
manufacturers confirmed that they do offer diesel firing while
operating in lean premix mode. The commenter is correct that we have no
emissions test data for lean premix units firing liquid fuel, however,
information provided by the manufacturers indicated that their emission
guarantees for CO and hydrocarbons were similar for both natural gas
and diesel. Also, testing on dual fuel diffusion flame units shows that
formaldehyde emissions are actually lower for distillate oil firing.
Therefore, we have established an emission standard for lean premix
oil-fired units in the final rule.
Comment: One commenter observed that HAP emissions from sources
burning natural gas are enormously different from sources burning other
fuels such as diesel. The commenter questioned EPA's argument that the
summation of emission factors for various HAP for different fuels is
comparable. The commenter also said that EPA does not explain what the
summation of emission factors means or how it might be relevant to
EPA's floors for any HAP.
Response: We agree with the commenter that the composition of HAP
emissions from sources burning natural gas is different than from
sources burning diesel fuel. Uncontrolled formaldehyde emissions are in
general lower as a result of the combustion of distillate oil than for
natural gas. Other differences in emissions between natural gas and
distillate oil include higher levels of pollutants such as PAH and
metals for stationary combustion turbines burning distillate oil. We
agree that the summation of emission factors for various HAP for
different fuels may be different. As discussed in the response to
previous comments, due to the differences in HAP emissions,
subcategories based on fuel were established for both diffusion flame
and lean premix turbines.
IV. Rationale for Selecting the Final Standards
A. How Did We Select the Source Category and Any Subcategories?
Stationary combustion turbines can be major sources of HAP
emissions and, as a result, we listed them as a major source category
for regulatory development under section 112 of the CAA, which allows
us to establish subcategories within a source category for the purpose
of regulation. Consequently, we evaluated several criteria associated
with stationary combustion turbines which might serve as potential
subcategories.
We identified emergency stationary combustion turbines as a
subcategory. Emergency stationary combustion turbines operate only in
emergencies, such as a loss of power provided by another source. These
types of stationary combustion turbines operate infrequently and, when
called upon to operate, must respond without failure and without
lengthy periods of startup. These conditions limit the applicability of
HAP emission control technology to emergency stationary combustion
turbines.
Similarly, stationary combustion turbines which burn landfill or
digester gas equivalent to 10 percent or more of the gross heat input
on an annual basis or where gasified MSW is used to generate 10 percent
or more of the gross heat input to the stationary combustion turbine on
an annual basis were identified as a subcategory. Landfill gas,
digester gas, and gasified MSW contain a family of chemicals referred
to as siloxanes, which limit the application of HAP emission control
technology.
Stationary combustion turbines of less than 1 MW rated peak power
output were also identified as a subcategory. We believe these small
stationary combustion turbines are few in number. These small
stationary combustion turbines are sufficiently dissimilar from larger
combustion turbines that we cannot evaluate the feasibility of emission
control technology based on information concerning the larger turbines.
To our knowledge, none of the smaller turbines use emission control
technology to reduce HAP. Therefore, we believe it would be
inappropriate to require HAP emission controls to be applied to them
without further information on control technology performance.
Stationary combustion turbines can be classified as either
diffusion flame or lean premix. We examined formaldehyde test data for
both diffusion flame and lean premix stationary combustion turbines and
observed that uncontrolled formaldehyde emissions for stationary lean
premix combustion turbines are significantly lower than those of
stationary diffusion flame combustion turbines. Due to the difference
in the two technologies, we decided to establish subcategories for
diffusion flame and lean premix stationary combustion turbines.
[[Page 10527]]
We further investigated subcategorizing lean premix turbines based
on fuel. At the time of proposal, EPA was not aware of the availability
of distillate oil fired stationary combustion turbines that operated in
the lean premix mode. We received comments indicating otherwise during
the public comment period from combustion turbine manufacturers. We
believe there is a difference in uncontrolled HAP emissions between
natural gas and distillate oil for stationary lean premix combustion
turbines. This is based on test data for stationary diffusion flame
combustion turbines which clearly show there is a difference in the
composition of uncontrolled HAP emissions between natural gas and
distillate oil. We believe this also would apply to stationary lean
premix combustion turbines. For stationary lean premix combustion
turbines, NOX emissions also vary depending on which fuel is
burned in the combustion process. Information from combustion turbine
vendors indicate that NOX emission guarantees for distillate
oil can be up to five times higher than the NOX emission
guarantees for natural gas for stationary lean premix combustion
turbines. Finally, the mass of total emissions may be similar for
natural gas and distillate oil, but some pollutants such as
formaldehyde are lower for distillate oil and other pollutants such as
PAH and metals are higher for oil. For all practical purposes,
uncontrolled natural gas metal emissions are nonexistent, while they
are emitted in small quantities when burning distillate oil.
We expect that the majority of distillate oil burned in stationary
combustion turbines will be fuel oil number 2. We recognize that
stationary combustion turbine owners and operators may burn different
varieties of distillate oil, however we believe that any other
distillate oil combusted will be of similar quality and composition to
fuel oil number 2. We do not anticipate that owners and operators will
burn any other liquid based fuel that is more contaminated with metals
than fuel oil number 2 and expect that most available liquid fuels that
may be used in stationary combustion turbines will be similar and
fairly consistent.
In recognition of the clear differences we found in the composition
of HAP emissions depending on the fuel that is used, we have determined
that it is appropriate to subcategorize further within stationary lean
premix combustion turbines based on fuel use. In devising appropriate
subcategories based on fuel use, we needed to consider that many
combustion turbines are configured both to use natural gas and
distillate oil. These dual fuel units typically burn natural gas as
their primary fuel, and only utilize distillate oil as a backup.
Without some allowance for this limited backup use of distillate oil,
these turbines might switch subcategories frequently, causing confusion
for sources and complicating compliance demonstrations. To limit the
frequency of switching between subcategories which would result from
limited usage of distillate oil as a backup fuel, we have defined the
lean premix gas-fired subcategory in a manner which permits turbines
that fire gas using lean premix technology to remain in the subcategory
if all turbines at the site in question fire oil no more than a total
of 1000 hours during the calendar year. We believe this 1000 hour
allowance will be sufficient to accommodate those situations where
distillate oil is used only as a backup. The lean premix gas-fired
turbines subcategory will be defined to include: (a) Each stationary
combustion turbine which is equipped only to fire gas using lean premix
technology, (b) each stationary combustion turbine which is equipped
both to fire gas using lean premix technology and to fire oil, during
any period when it is firing gas, and (c) each stationary combustion
turbine which is equipped both to fire gas using lean premix technology
and to fire oil, and is located at a major source where all stationary
combustion turbines fire oil no more than an aggregate total of 1000
hours during the calendar year.
The lean premix oil-fired turbines subcategory will be defined to
include: (a) each stationary combustion turbine which is equipped only
to fire oil using lean premix technology, and (b) each stationary
combustion turbine which is equipped both to fire oil using lean premix
technology and to fire gas, and is located at a major source where all
stationary combustion turbines fire oil more than an aggregate total of
1000 hours during the calendar year, during any period when it is
firing oil. We do not know of any actual combustion turbines which
would be in this subcategory, but this is possible because we have been
advised that combustion turbines can be configured to burn oil using
lean premix technology.
We further investigated subcategorizing diffusion flame turbines
based on fuel. For diffusion flame turbines, test data show that HAP
emissions vary depending on which fuel is burned. Formaldehyde
emissions are in general lower for diffusion flame units firing
distillate oil versus diffusion flame units firing natural gas.
Emissions data also show that NOX levels are higher for
diffusion flame units firing distillate oil than diffusion flame units
firing natural gas. Finally, other fuel differences between natural gas
and distillate oil include higher levels of pollutants such as PAH and
metals in the emissions of stationary diffusion flame combustion
turbines burning distillate oil. Quantities of these pollutants are
small for distillate oil; metal emissions from natural gas are at non-
detectable levels. As previously indicated, we expect that most owners
and operators of stationary combustion turbines will burn distillate
oil of the form fuel oil number 2. However, we recognize that other
liquid based fuels may be also be fired, but these fuels will be
similar to fuel oil number 2, and do not expect owners and operators to
burn any other fuel that is more contaminated with metals.
As in the case of the lean premix turbines, we concluded based on
the clear differences in the composition of HAP emissions depending on
the fuel that is used that it is appropriate to subcategorize further
within stationary diffusion flame combustion turbines based on fuel
use. As in the case of the lean premix turbines, we have included a
1000 hour per site allowance for limited backup use of distillate oil
in order to limit the frequency that dual fuel turbines will switch
subcategories. We believe this 1000 hour allowance will be sufficient
to accommodate those situations where distillate oil is used only as a
backup.
The diffusion flame gas-fired turbines subcategory will be defined
to include: (a) Each stationary combustion turbine which is equipped
only to fire gas using diffusion flame technology, (b) each stationary
combustion turbine which is equipped both to fire gas using diffusion
flame technology and to fire oil, during any period when it is firing
gas, and (c) each stationary combustion turbine which is equipped both
to fire gas using diffusion flame technology and to fire oil, and is
located at a major source where all stationary combustion turbines fire
oil no more than an aggregate total of 1000 hours during the calendar
year.
The diffusion flame oil-fired turbines subcategory will be defined
to include: (a) each stationary combustion turbine which is equipped
only to fire oil using diffusion flame technology, and (b) each
stationary combustion turbine which is equipped both to fire oil using
diffusion flame technology and to fire gas, and is located at a major
source where all stationary combustion turbines fire oil more than an
aggregate total of 1000 hours during the calendar year, during
[[Page 10528]]
any period when it is firing oil. We expect that the vast majority of
all stationary combustion turbines which are primarily oil-fired will
be included in this subcategory.
Stationary combustion turbines located on the North Slope of Alaska
have been identified as a subcategory due to operation limitations and
uncertainties regarding the application of controls to these units.
There are very few of these units, and none have installed emission
controls for the reduction of HAP.
B. What Are the Requirements for Stationary Combustion Turbines Located
at Area Sources?
The final rule does not apply to stationary combustion turbines
located at an area source of HAP emissions. An area source is any
source that is not a major source of HAP emissions. In developing our
Urban Air Toxics Strategy, we identified area sources we believe
warrant regulation to protect the environment and the public health and
satisfy the statutory requirements in section 112 of the CAA pertaining
to area sources. Stationary combustion turbines located at area sources
were not included on that list. As a result, the final rule does not
apply to these stationary combustion turbines.
C. What Is the Affected Source?
The final rule applies to any stationary combustion turbine located
at a major source. Consequently, a stationary combustion turbine
located at major sources of HAP emissions is the affected source under
the final rule.
The General Provisions at 40 CFR 63.2 require us to generally adopt
a broad definition of affected source, which includes all emission
units within each subcategory that are located within the same
contiguous area. However, Sec. 63.2 also provides that we may adopt a
narrower definition of affected source in instances where we determine
that the broader definition would ``create significant administrative,
practical, or implementation problems'' and ``the different definition
would resolve those problems.'' This is such an instance.
Although we have taken some steps in the definition of
subcategories to limit the frequency of switching between
subcategories, we cannot eliminate the possibility that some individual
turbines will be switched from one subcategory to another. Use of the
broader definition of affected source specified by the General
Provisions would require very complex aggregate compliance
determinations because an individual turbine could be part of one
affected source at one time and part of a different affected source at
another time. This would require that the contribution of each turbine
to total emissions for all emission units within each subcategory be
adjusted to reflect the proportionate time the unit was operating
within that subcategory. Such complicated compliance determinations are
impractical and, therefore, we have decided to adopt a definition which
establishes each individual combustion turbine as the affected source.
D. How Did We Determine the Basis and Level of the Emission Limitations
for Existing Sources?
As established in section 112 of the CAA, the MACT standards must
be no less stringent than the MACT floor. The MACT floor for existing
sources is the average emission limitation achieved by the best
performing 12 percent of existing sources in the subcategory (or the
best performing five existing sources in subcategories with fewer than
30 sources).
From the applicable judicial precedent, we can derive certain basic
principles which we must follow in deriving the MACT floor. All HAP
emitted by sources in the category or subcategory in question must be
considered in determining the MACT floor. If a particular HAP is an
appropriate surrogate for evaluating emission reductions which have
been achieved for a group of HAP, the MACT floor may be expressed in
terms of that HAP. However, we must explain our basis for concluding
there is a relationship between control of emissions of the HAP we
utilize to characterize the MACT floor and control of other HAP. If we
determine that the MACT floor requires differing controls affecting
more than one group of HAP, multiple measures of the MACT floor may be
necessary.
In addition, when deriving the MACT floor for a particular category
or subcategory, we must consider all measures which could result in
reduction of HAP emissions. These measures will include potential
installation of add-on control technology, but other operational
modifications such as adjustment of equipment, revision of work
practices, and material substitution should also be considered. Where
emissions are relatively homogeneous across the sources in a category
or subcategory, and any variation in HAP emissions which does occur
cannot be readily attributed to differences in any factor which is
susceptible to control by the owner or operator, the MACT floor for a
particular HAP or group of HAP may be expressed in terms of reductions
achieved by use of potential add-on controls.
Existing Lean Premix Combustion Turbines
As explained above, we have established two subcategories of
stationary lean premix combustion turbines, lean premix gas-fired
turbines and lean premix oil-fired turbines. Emissions of each HAP are
relatively homogeneous within each of these two subcategories, and any
variation in HAP emissions cannot be readily controlled except by add-
on control. To determine the MACT floor for both subcategories of
existing stationary lean premix combustion turbines, the EPA's
combustion turbine inventory database was consulted.
The inventory database provides population information on
stationary combustion turbines in the United States (U.S.) and was
constructed in order to support the development of the rule. Data in
the inventory database are based on information from available
databases, such as the Aerometric Information Retrieval System (AIRS),
the Ozone Transport and Assessment Group (OTAG), and State and local
agencies' databases. The first version of the database was released in
1997. Subsequent versions have been released reflecting additional or
updated data. The most recent release of the database is version 4,
released in November 1998.
The inventory database contains information on approximately 4,800
stationary combustion turbines. The current stationary combustion
turbine population is estimated to be about 8,000 turbines. Therefore,
the inventory database represents about 60 percent of the stationary
combustion turbines in the U.S. At least 20 percent of those turbines
are estimated to be lean premix combustion turbines, based on
conversations with turbine manufacturers.
The information contained in the inventory database is believed to
be representative of stationary combustion turbines primarily because
of its comprehensiveness. The database includes both small and large
stationary combustion turbines in different user segments. Forty-eight
percent are ``industrial,'' 39 percent are ``utility,'' and 13 percent
are ``pipeline.'' Note that independent power producers (IPP) are
included in the utility and industrial segments.
We examined all of the information available to us including the
inventory database to identify any operational modifications such as
equipment adjustments or work practice revisions which might be
associated with lower
[[Page 10529]]
HAP emissions. We were unsuccessful in identifying any such operational
modifications. Therefore, we were unable to utilize any factors other
than add-on controls in deriving the MACT floor.
Another approach we investigated to identify a MACT floor was to
review the requirements in existing State regulations and permits. No
State regulations exist for HAP emission limits for stationary
combustion turbines. Only one State permit limitation for a single HAP
(benzene) was identified. Therefore, we were unable to use State
regulations or permits in deriving a MACT floor.
The only add-on control technology currently proven to reduce HAP
emissions from stationary lean premix combustion turbines is an
oxidation catalyst emission control device. At proposal, the inventory
database indicated that no existing stationary lean premix combustion
turbines were controlled with oxidation catalyst systems. During the
public comment period, we received a test report where a lean premix
combustion turbine burning natural gas was tested twice about 2 years
apart with an oxidation catalyst in operation.
We estimate that about 1 percent of existing lean premix gas-fired
turbines may have oxidation catalyst systems installed. Accordingly,
the average of the best performing 12 percent is no emission reduction.
Therefore, the MACT floor for existing lean premix gas-fired turbines
for each individual HAP is no emission reduction.
For lean premix oil-fired turbines, we do not have any data
indicating that turbines in this subcategory are in actual use, nor do
we have data indicating that oxidation catalysts have been installed.
Accordingly, the average emission limitation achieved by the best
performing existing units in this subcategory for each individual HAP
would also be no emission reduction.
To determine MACT for both subcategories of existing stationary
lean premix combustion turbines, we evaluated regulatory alternatives
more stringent than the MACT floor. We considered requiring the use of
an oxidation catalyst emission control device. According to catalyst
vendors, oxidation catalysts are currently being used on some existing
lean premix stationary combustion turbines. In addition, we recently
received a test report where testing was conducted on a lean premix
unit with an oxidation catalyst. However, an analysis of the
application of oxidation catalyst control to existing lean premix
stationary combustion turbines showed that the incremental cost per ton
of HAP removed was excessive. We have not identified any operational
modifications which are not currently in use for these turbines but
might result in HAP reductions. Nor have we identified any technologies
to control those metallic HAP which may be emitted during burning of
distillate oil which are technologically feasible and cost-effective.
For these reasons, we concluded that MACT for each individual HAP for
existing sources in both subcategories of existing stationary lean
premix combustion turbines is the same as the MACT floor, i.e., no
emission reduction.
Existing Diffusion Flame Combustion Turbines
As explained above, we have established two subcategories of
stationary diffusion flame combustion turbines, diffusion flame gas-
fired turbines and diffusion flame oil-fired turbines. We believe
emissions of each HAP are relatively homogeneous within each of these
two subcategories and any variation in HAP emissions cannot be readily
controlled except by add-on control. To determine the MACT floor for
both subcategories of existing stationary diffusion flame combustion
turbines, we consulted the inventory database previously discussed in
this preamble. At least 80 percent of those turbines are assumed to be
diffusion flame combustion turbines, based on conversations with
turbine manufacturers.
We investigated the use of operational modifications such as
equipment adjustments and work practice revisions for stationary
diffusion flame combustion turbines to determine if HAP reductions
associated with such operational modifications might be relevant in
deriving the MACT floor. We found no relevant references in the
inventory database.
Most stationary diffusion flame combustion turbines will not
operate unless preset conditions established by the manufacturer are
met. Stationary diffusion flame combustion turbines, by manufacturer
design, permit little operator involvement and there are no operating
parameters, such as air/fuel ratio, for the operator to adjust. We
concluded, therefore, that there are no specific operational
modifications which could reduce HAP emissions or which could serve to
identify a MACT floor.
Another approach we investigated to identify a MACT floor was to
review the requirements in existing State regulations and permits. No
State regulations exist for HAP emission limits for stationary
combustion turbines. Only one State permit limitation for a single HAP
(benzene) was identified. Therefore, we were unable to use State
regulations or permits in deriving a MACT floor.
We examined the inventory database for information on HAP emission
control technology. There were no turbines controlled with oxidation
catalyst systems in the inventory database so we used information
supplied by catalyst vendors. There are about 200 oxidation catalyst
systems installed in the U.S. The only control technology currently
proven to reduce HAP emissions from stationary diffusion flame
combustion turbines is an oxidation catalyst emission control device,
such as a CO oxidation catalyst. These control devices are used to
reduce CO emissions and are currently installed on several stationary
combustion turbines.
Less than 3 percent of existing stationary diffusion flame gas-
fired turbines in the U.S., based on information in our inventory
database and information from catalyst vendors, are equipped with
oxidation catalyst emission control devices. Therefore, the average
emission limitation for the best performing 12 percent of existing
diffusion flame gas-fired turbines is no emission reduction and the
MACT floor for each individual HAP for existing turbines in this
subcategory is also no emission reduction.
We estimate that less than 1 percent of existing stationary
diffusion flame oil-fired turbines have oxidation catalyst systems
installed. Thus, the average of the best performing 12 percent of
existing diffusion flame oil-fired turbines is no emission reduction
for organic HAP. No technologies to control metallic HAP have been
installed on the existing turbines in this subcategory. Therefore, the
MACT floor for each individual HAP for existing turbines in the
diffusion flame oil-fired subcategory is no emission reduction.
To determine MACT for both subcategories of existing diffusion
flame combustion turbines, regulatory alternatives more stringent than
the MACT floor were evaluated. One beyond-the-floor regulatory option
is requiring an oxidation catalyst. However, cost per ton estimates of
oxidation catalyst emission control devices for control of total HAP
from stationary diffusion flame combustion turbines were deemed
excessive. In addition, we did not identify any operational
modifications which are not currently in use for these turbines but
might result in HAP reductions. Moreover, we did not identify any
[[Page 10530]]
technologies to control those metallic HAP which may be emitted during
burning of distillate oil which are technologically feasible and cost-
effective. For these reasons, MACT for each individual HAP for turbines
in both subcategories of existing stationary diffusion flame combustion
turbines is the same as the MACT floor, i.e., no emission reduction.
E. How Did We Determine the Basis and Level of the Emission Limitations
and Operating Limitations for New Sources?
For new sources, the MACT floor is defined as the emission control
that is achieved in practice by the best controlled similar source. To
be a similar source, a source should not have any characteristics that
differ sufficiently to have a material effect on the feasibility of
emission controls, but the source need not be in the same source
category or subcategory.
We considered using a surrogate in order to reduce the costs
associated with monitoring while at the same time being relatively sure
that the pollutants the surrogate is supposed to represent are also
controlled. We investigated the use of formaldehyde concentration as a
surrogate for all organic HAP emissions. Formaldehyde is the HAP
emitted in the highest concentrations from stationary combustion
turbines. Formaldehyde, toluene, benzene, and acetaldehyde account for
essentially all the mass of HAP emissions from the stationary
combustion turbine exhaust, and emissions data show that these
pollutants are equally controlled by an oxidation catalyst.
Information from testing conducted on a diffusion flame combustion
turbine equipped with an oxidation catalyst control system indicated
that the formaldehyde and acetaldehyde emission reduction efficiency
achieved was 97 and 94 percent, respectively. Later, after review of an
expert task group, the conclusion reached was that both formaldehyde
and acetaldehyde were controlled at least 90 percent. In addition,
emissions tests conducted on reciprocating internal combustion engines
(RICE) at Colorado State University (CSU) in 1998 showed that the
benzene emission reduction efficiency across an oxidation catalyst
averaged 73 percent, and the toluene emission reduction averaged 77
percent for 16 runs at various engine conditions on a two-stroke lean
burn engine. The toluene emission reduction efficiency across the
oxidation catalyst averaged 85 percent for ten runs at various engine
conditions on a compression ignition RICE. We would expect the
emissions reductions efficiencies for benzene and toluene from
combustion turbines to be as high or higher than those reported for the
CSU RICE tests since combustion turbines catalyst temperatures are
generally higher. Finally, catalyst performance information obtained
from a catalyst vendor indicated that the percent conversion for an
oxidation catalyst system installed on combustion turbines did not vary
significantly between formaldehyde, benzene, and toluene. The percent
conversion was measured at 77, 72, and 71 for formaldehyde, benzene,
and toluene, respectively. Although emissions reductions for large
molecules may in theory be less than for formaldehyde, the above
information shows that formaldehyde is a good surrogate for the most
significant HAP pollutants emitted from combustion turbines as
demonstrated by evaluating the reduction efficiency of larger, heavier
molecules, hence taking differences in molecular density into account.
In addition, emission data show that HAP emission levels and
formaldehyde emission levels are related, in the sense that when
emissions of one are low, emissions of the other are low and vice
versa. This leads us to conclude that emission control technologies
which lead to reductions in formaldehyde emissions will lead to
reductions in organic HAP emissions. For the reasons provided above, it
is appropriate to use formaldehyde as a surrogate for all organic HAP
emissions.
New Lean Premix Gas-Fired Turbines
To determine the MACT floor for new stationary lean premix gas-
fired turbines, we reviewed the emissions data we had available at
proposal and additional test reports received during the comment
period. In order to set the MACT floor for new sources in this
subcategory, we chose the best performing turbine. Emissions of each
HAP are relatively homogeneous within the subcategory of stationary
lean premix gas-fired turbines and any variation in HAP emissions
cannot be readily controlled except by add-on control. The best
performing turbine is equipped with an oxidation catalyst.
The formaldehyde concentration from the best performing turbine was
measured at the outlet of the control device using CARB 430. Concerns
were raised during the public comment period that CARB 430 formaldehyde
results can be biased low as compared to formaldehyde results obtained
by FTIR. For a comprehensive discussion of test methods and the
development of the correlation between CARB 430 and FTIR formaldehyde
levels, please refer to the memorandum entitled ``Review of Test
Methods and Data used to Quantify Formaldehyde Concentrations from
Combustion Turbines'' in the docket. A bias factor of 1.7 was,
therefore, applied to the formaldehyde concentration of the best
performing turbine. The best performing turbine was tested twice under
the same conditions about 2 years apart where one test measured 19
ppbvd and the other test measured 91 ppbvd formaldehyde (numbers have
been bias corrected). We determined that since both of these tests were
performed under similar conditions but at different times, this
represented the variability of the best performing unit and used the
higher value as the MACT floor. The MACT floor for organic HAP for new
stationary lean premix gas-fired turbines is, therefore, an emission
limit of 91 ppbvd formaldehyde at 15 percent oxygen.
We recognize that our selection of an emission limit of 91 ppbvd
formaldehyde is based on quite limited data. We think that each new
combustion turbine in this subcategory should be able to achieve
compliance with this limit if an oxidation catalyst is properly
installed and operated. If actual emission data demonstrate that we are
incorrect, and that sources which properly install and operate an
oxidation catalyst cannot consistently achieve compliance, we will
revise the standard accordingly.
No beyond-the-floor regulatory alternatives were identified for new
lean premix gas-fired turbines. We are not aware of any add-on control
devices which can reduce organic HAP emissions to levels lower than
those resulting from the application of oxidation catalyst systems. We,
therefore, determined that MACT for organic HAP emissions from new
stationary lean premix gas-fired turbines is the same as the MACT
floor, i.e., an emission limit of 91 ppbvd formaldehyde at 15 percent
oxygen.
New Lean Premix Oil-Fired Turbines
We do not have any tests for lean premix combustion turbines firing
any other fuels besides natural gas. However, we expect that emissions
of organic HAP will be controlled by installation of an oxidation
catalyst on any units in this subcategory to a degree similar to lean
premix gas-fired turbines and diffusion flame oil-fired turbines. We
also expect that organic HAP emissions from lean premix oil-fired
turbines would be equal to or less than organic HAP emissions from lean
premix gas-fired turbines. We have these expectations based on the fact
that dual-fuel units using oxidation catalyst systems operate on
distillate oil and the
[[Page 10531]]
fact that catalyst vendors indicate that oxidation catalyst systems
operate equally well on either fuel. Therefore, we used the best
performing turbine from the lean premix gas-fired turbine subcategory
to set the MACT floor for lean premix oil-fired turbines. As a result,
the MACT floor for organic HAP for new stationary lean premix oil-fired
turbines is an emission limit of 91 ppbvd formaldehyde at 15 percent
oxygen.
We are not aware of any similar sources which are equipped with
emission control devices that could also reduce emissions of metallic
HAP. We also examined the inventory database in an attempt to identify
any operating modifications which might reduce metal emissions, but
could not identify any such practices. We also referred to the
inventory database to determine if any similar sources are equipped
with emission controls for the reduction of particulate matter (PM)
which would also reduce metal emissions. No such units were found in
the inventory database and none were identified by commenters during
the public comment period. For this reason, the MACT floor for new
stationary lean premix oil-fired turbines is no emission control for
metallic HAP emissions.
We were unable to identify any beyond-the-floor regulatory
alternatives for new stationary lean premix oil-fired turbines. We know
of no emission control technology currently available which can reduce
HAP emissions to levels lower than those achieved through use of an
oxidation catalyst. We also have not identified any add-on controls for
metallic HAP. We conclude, therefore, that MACT for new lean premix
oil-fired turbines would be equivalent to the MACT floor, i.e., an
emission limit of 91 ppbvd formaldehyde at 15 percent oxygen organic
HAP, and no emission reduction for metallic HAP.
New Diffusion Flame Gas-Fired Turbines
In the proposed rule, we requested sources to submit any HAP
emissions test data available from stationary combustion turbines.
After the proposal, we also contacted several State agencies to request
emissions test data from diffusion flame combustion turbines. Due to
the CARB advisory issued on April 28, 2000, which stated that
formaldehyde emissions data where the NOX levels were
greater than 50 ppmvd were suspect and should be flagged as non-
quantitative, we conducted an analysis of existing diffusion flame
emissions test data. Tests where the NOX emissions were
greater than 50 ppm or tests where the NOX levels were
unknown were excluded from our analysis. Most of the diffusion flame
tests in the emissions database were unable to pass the screening.
Therefore, we specifically requested States to provide test reports for
diffusion flame combustion turbines where Method 320 was used, or CARB
430 was used and the NOX emissions were below 50 ppmvd.
During the comment period we received three additional test reports for
testing conducted on a total of five stationary diffusion flame
combustion turbines.
To identify the MACT floor for new stationary diffusion flame gas-
fired turbines, we based our analysis on the performance of the best
turbine. Individual HAP emissions are relatively homogeneous within the
subcategory of stationary diffusion flame gas-fired turbines and any
variation in HAP emissions cannot be readily controlled except by add-
on control. The best performing turbine in this subcategory is equipped
with an oxidation catalyst.
As previously indicated, formaldehyde is the HAP emitted in the
highest concentrations from stationary combustion turbines and data
show control of organic HAP emissions and formaldehyde emissions are
related. We have, therefore, concluded that formaldehyde is an
appropriate surrogate for all organic HAP emissions.
Formaldehyde was measured by CARB 430 at the outlet of the
oxidation catalyst. We applied a bias factor of 1.7 to the formaldehyde
concentration obtained by CARB 430 for the best performing turbine. The
corrected outlet concentration of formaldehyde from the best performing
turbine was 15 ppbvd. We only have one controlled test for this
turbine, but we expect that similar variability would be associated
with this turbine as was associated with the best performing lean
premix turbine. Therefore, applying a factor of 5 to the formaldehyde
concentration measured at the outlet of the best performing diffusion
flame turbine is appropriate to account for variability. Therefore, we
would establish a formaldehyde emission limitation of 75 ppbvd based on
the outlet of the control device. However, with a similar control
system, we would expect that the emission limit should be no lower than
the emission limit for lean premix turbines since diffusion flame
turbines on average emit more HAP. The MACT floor for new stationary
diffusion flame combustion gas-fired turbines is, therefore, an
emission limit of 91 ppbvd formaldehyde at 15 percent oxygen.
We were unable to identify any beyond-the-floor regulatory
alternatives for new stationary diffusion flame gas-fired turbines. We
know of no emission control technology currently available which can
reduce organic HAP emissions to levels lower than that achieved through
the use of an oxidation catalyst. We concluded, therefore, that MACT
for organic HAP emissions from new diffusion flame stationary gas-fired
turbines is equivalent to the MACT floor, i.e., an emission limit of 91
ppbvd formaldehyde at 15 percent oxygen.
New Diffusion Flame Oil-Fired Turbines
To determine the MACT floor for new diffusion flame oil-fired
turbines, we again based our analysis on the best performing turbine.
Emissions of each individual HAP are relatively homogeneous within
stationary diffusion flame oil-fired turbines and any variation in HAP
emissions cannot be readily controlled except by add-on control. The
best performing turbine in this subcategory is equipped with an
oxidation catalyst.
As previously described in more detail, we are using formaldehyde
as a surrogate for all organic HAP emissions. The formaldehyde was
measured with EPA Method 0011 at the outlet of the control device. The
EPA Method 0011 is similar to CARB 430 and the problems associated with
CARB 430 are expected to be associated with EPA Method 0011. So again
we applied a bias factor of 1.7 to the formaldehyde outlet
concentration of the best performing diffusion flame oil-fired turbine.
The corrected formaldehyde concentration from this turbine is 44 ppbvd.
We only had one controlled test for this turbine, but would expect some
variability as has been shown with other turbines. However, since
formaldehyde emissions from distillate oil fired turbines are lower on
average by a factor of 1.4, we do not believe that the MACT emission
limit should be set higher than the emission limit for new stationary
diffusion flame gas-fired turbines. Therefore, the MACT floor for
organic HAP for new stationary diffusion flame oil-fired turbines is an
emission limit of 91 ppbvd formaldehyde at 15 percent oxygen.
We examined the inventory database to identify any operating
practices which could affect metal emissions. We were unable to
identify any such practices. We also determined that no similar sources
are equipped with emission control devices for the reduction of PM
which could also reduce metal emissions. Therefore, the MACT floor for
metallic HAP for new diffusion flame oil-fired turbines is no emission
reduction.
[[Page 10532]]
To determine MACT for new stationary diffusion oil-fired turbines,
we tried to identify beyond-the-floor options. There are currently no
beyond-the-floor regulatory alternatives for this subcategory as we
know of no emission control technology current available that can
reduce organic HAP emissions to levels lower than that obtained with
the use of an oxidation catalyst. We also have not identified any add-
on controls for metallic HAP. We conclude, therefore, that MACT for new
diffusion flame oil-fired turbines would be equivalent to the MACT
floor, i.e., an emission limit of 91 ppbvd formaldehyde at 15 percent
oxygen organic HAP, and no emission reduction for metallic HAP.
Other Subcategories
Although the final rule will apply to all stationary combustion
turbines located at major sources of HAP emissions, emergency
stationary combustion turbines, stationary combustion turbines which
burn landfill or digester gas equivalent to 10 percent or more of the
gross heat input on an annual basis or where gasified MSW is used to
generate 10 percent or more of the gross heat input to the stationary
combustion turbine on an annual basis, stationary combustion turbines
of less than 1 MW rated peak power output, and stationary combustion
turbines located on the North Slope of Alaska are not required to meet
the emission limitations or operating limitations.
For each of the other subcategories of stationary combustion
turbines, we have concerns about the applicability of emission control
technology. For example, emergency stationary combustion turbines
operate infrequently. In addition, when called upon to operate they
must respond immediately without failure and without lengthy startup
periods. This infrequent operation limits the applicability of HAP
emission control technology.
Landfill and digester gases contain a family of silicon based gases
called siloxanes. Siloxanes are also a component of municipal waste.
Combustion of siloxanes forms compounds that can foul post-combustion
catalysts, rendering catalysts inoperable within a very short period of
time. It is our judgment based on public comments that firing even 10
percent landfill or digester gas will cause fouling that will render
the oxidation catalyst inoperable within a short period of time.
Pretreatment of exhaust gases to remove siloxanes was investigated.
However, no pretreatment systems are in use and their long term
effectiveness is unknown. We also considered fuel switching for this
subcategory of turbines. Switching to a different fuel such as natural
gas or diesel would potentially allow the turbine to apply an oxidation
catalyst emission control device. However, fuel switching would defeat
the purpose of using this type of fuel which would then either be
allowed to escape uncontrolled or would be burned in a flare with no
energy recovery. We believe that switching landfill or digester gas or
gasified MSW to another fuel is inappropriate and is an environmentally
inferior option.
For stationary combustion turbines of less than 1 MW rated peak
power output, we have concerns about the effectiveness of scaling down
the oxidation catalyst emission control technology. Just as there are
often unforeseen problems associated with scaling up a technology,
there can be problems associated with scaling down a technology.
Stationary combustion turbines located on the North Slope of Alaska
have been identified as a subcategory due to operation limitations and
uncertainties regarding the application of controls to these units.
There are very few of these units; in addition, none have installed
emission controls for the reduction of HAP.
As a result, we identified subcategories for each of these types of
stationary combustion turbines and investigated MACT floors and MACT
for each subcategory. As expected, since we identified these types of
stationary combustion turbines as separate subcategories based on
concerns about the applicability of emission control technology, we
found no stationary combustion turbines in these subcategories using
any emission control technology to reduce HAP emissions. As discussed
above, we are not aware of any work practices that might constitute a
MACT floor, nor did we find that the use of a particular fuel results
in HAP emission reductions. The MACT floor, therefore, for each of
these subcategories is no emission reduction.
Despite our concerns with the applicability of emission control
technology, we examined the cost per ton of HAP removed for these
subcategories. This analysis can be found in the docket (Docket ID No.
OAR-2002-0060 (A-95-51)) for the final rule. Whether our concerns are
warranted or not, we consider the incremental cost per ton of HAP
removed excessive--primarily because of the very small reduction in HAP
emissions that would result.
We also considered the non-air health, environmental, and energy
impacts of an oxidation catalyst system, as discussed previously in
this preamble, and concluded that there would be only a small energy
impact and no non-air health or environmental impacts. However, as
stated above, we did not adopt this regulatory option due to cost
considerations and concerns about the applicability of this technology
to these subcategories. We were not able to identify any other means of
achieving HAP emission reduction for these subcategories.
As a result, for all of these reasons, we conclude that MACT for
these subcategories is the MACT floor (i.e., no emission reduction).
F. How Did We Select the Initial Compliance Requirements?
New and reconstructed sources complying with the emission
limitation for formaldehyde emissions are required to conduct an
initial performance test. The purpose of the initial test is to
demonstrate initial compliance with the formaldehyde emission
limitation.
G. How Did We Select the Continuous Compliance Requirements?
If you must comply with the emission limitations, continuous
compliance with these requirements is required at all times except
during startup, shutdown, and malfunction of your stationary combustion
turbine. You are required to develop a startup, shutdown, and
malfunction plan.
We considered requiring FTIR CEMS; however, we concluded that the
costs of FTIR CEMS were excessive and were not yet demonstrated at the
low formaldehyde levels of the standards. We considered requiring those
sources to continuously monitor operating load to demonstrate
continuous compliance because the data establishing the formaldehyde
outlet concentration level are based on tests that were done at high
loads. However, we believe that the performance of a stationary
combustion turbine at high load is also indicative of its operation at
lower loads. In fact, the operator can make no parameter adjustments
that would lead to lower emissions.
For these reasons, EPA determined that it would be appropriate to
require sources that comply with the emission limitation for
formaldehyde emissions and that use an oxidation catalyst emission
control device to continuously monitor the oxidation catalyst inlet
temperature. Continuously monitoring the oxidation catalyst inlet
temperature and maintaining this temperature within the range
recommended by the
[[Page 10533]]
catalyst manufacturer will ensure proper operation of the oxidation
catalyst emission control device and continuous compliance with the
emission limitation for formaldehyde.
Sources that do not use an oxidation catalyst emission control
device are required to petition the Administrator for approval of
operating limitations or approval of no operating limitations.
H. How Did We Select the Testing Methods To Measure These Low
Concentrations of Formaldehyde?
The final rule requires the use of Method 320 or ASTM D6348-03 to
determine compliance with the emission limitation for formaldehyde.
With regard to formaldehyde, we believe systems meeting the
requirements of Method 320, a self-validating FTIR method, can be used
to attain detection limits for formaldehyde concentrations well below
the current emission limitations with a path length of 10 meters or
less. Some of the older technology may require 100 or even 200 meter
path lengths. We expect state-of-the-art digital signal processing (to
reduce signal to noise ratio) would be needed. Method 320 also includes
formaldehyde spike recovery criteria, which require spike recoveries of
70 to 130 percent.
While we believe FTIR systems can meet the requirements of Method
320 and measure formaldehyde concentrations at these low levels, we
have limited experience with their use. As a result, we solicited
comments on the ability and use of FTIR systems to meet the validation
and quality assurance requirements of Method 320 for the purpose of
determining compliance with the emission limitation for formaldehyde.
Commenters were generally in agreement that Method 320 is the most
accurate and reliable test method currently available to test for
formaldehyde emissions from the stationary combustion turbine exhaust.
We are also allowing the use of ASTM D6348-03 in the final rule to
determine compliance with the emission limitation for formaldehyde. As
mentioned in the preamble to the proposed rule, the method was reviewed
by the EPA as a potential alternative to Method 320. Suggested
revisions to ASTM D6348-98 were sent to ASTM by the EPA that would
allow the EPA to accept ASTM D6348-98 as an acceptable alternative. The
ASTM has revised the method following EPA's suggested revisions. The
EPA has determined that the revised method, ASTM D6348-03, ``Standard
Test Method for Determination of Gaseous Compounds by Extractive Direct
Interface Fourier Transform Infrared (FTIR) Spectroscopy,'' is an
acceptable alternative to Method 320 for formaldehyde measurement.
As an alternative to Method 320, we proposed Method 323 for natural
gas-fired sources. Method 323 uses the acetyl acetone colorimetric
method to measure formaldehyde emissions in the exhaust of natural gas-
fired, stationary combustion sources. Commenters did not support Method
323 and were concerned whether this method could provide reliable
results. In addition, Method 323 has not been validated or demonstrated
for use on stationary combustion turbines emitting low formaldehyde
emissions. Therefore, Method 323 has not been included as a compliance
method for formaldehyde in the final rule.
At proposal we believed CARB Method 430 and EPA SW-846 Method 0011
were capable of measuring formaldehyde concentrations at these low
levels. Commenters were not supportive of these methods. In addition,
CARB 430 is susceptible to interferences and sample loss contributes to
large measurement variability. Method 0011 uses a similar analytical
approach to CARB 430 and has many shortcomings and limited application
opportunities. Accordingly, we are not including CARB 430 and Method
0011 in the final rule.
For these reasons, EPA has specified that Method 320 or ASTM D6348-
03 should be used to determine compliance with the formaldehyde
emission limitation in the final rule.
I. How Did We Select the Notification, Recordkeeping and Reporting
Requirements?
The notification, recordkeeping, and reporting requirements are
based on the NESHAP General Provisions of 40 CFR part 63.
V. Summary of Environmental, Energy and Economic Impacts
We estimate that 20 percent of the stationary combustion turbines
affected by the final rule will be located at major sources. As a
result, the environmental, energy, and economic impacts presented in
this preamble reflect these estimates.
The outcome of the petition to delist certain subcategories which
has been submitted to EPA could significantly affect the estimated
impacts of the final rule. If approved, the delisting could
significantly decrease the number of sources affected by the final rule
and could affect the final emission estimates. Thus, the estimated
impacts could change.
A. What Are the Air Quality Impacts?
The final rule will reduce total national HAP emissions by an
estimated 98 tpy in the 5th year after the standards are promulgated.
The emission reduction achieved by the final rule would be due to the
sources that install an oxidation catalyst control system. We estimate
that all new stationary combustion turbines will install oxidation
catalyst control to comply with the standards.
To estimate air impacts, national HAP emissions in the absence of
the final rule (i.e., HAP emission baseline) were calculated. We then
assumed a HAP reduction of 90 percent, achieved by using oxidation
catalyst emission control devices to comply with the formaldehyde
emission limitation, and applied this reduction to the baseline HAP
emissions to estimate total national HAP emission reduction. The total
national HAP emission reduction is the sum of formaldehyde,
acetaldehyde, benzene, and toluene emissions reductions. In addition to
HAP emission reduction, the final rule will reduce criteria air
pollutant emissions, primarily CO emissions.
B. What Are the Cost Impacts?
The national total annualized cost of the final rule in the 5th
year following promulgation is estimated to be about $43 million.
Approximately $147,400 of that amount is the estimated annualized cost
for monitoring, recordkeeping, and reporting. To calculate the
annualized control costs, we obtained estimates of the capital costs of
oxidation catalyst emission control devices from vendors. We then
calculated the national total annualized costs of control for the new
stationary combustion turbines installing oxidation catalyst emission
control in the next 5 years. Our projection of new stationary
combustion turbine capacity that will come online during the next 5
years is based on estimates from the Department of Energy indicating
that 218 new stationary combustion turbines will begin operation
between 2002 and 2007.
C. What Are the Economic Impacts?
The EPA prepared an economic impact analysis to evaluate the
impacts the final rule would have on combustion turbines producers,
consumers of goods and services produced by combustion turbines, and
society. The analysis shows minimal changes in prices and output for
products made by the 24 industries affected by the final rule. The
price increase for affected output is less than 0.02 percent and the
reduction in output
[[Page 10534]]
is less than 0.02 percent for each affected industry. Estimates of
impacts on fuel markets show price increases of less than 0.06 percent
for petroleum products and natural gas, and price increases of 0.53 and
0.72 percent for base-load and peak-load electricity, respectively. The
price of coal is expected to decline by about 0.24 percent, and this is
due to a small reduction in demand for this fuel type. Reductions in
output are expected to be less than 0.67 percent for each energy type,
including base-load and peak-load electricity. The social costs of the
final rule are estimated at $7.8 million (1998 dollars). Social costs
include the compliance costs, but also include those costs that reflect
changes in the national economy due to changes in consumer and producer
behavior in response to the compliance costs associated with a
regulation. In this case, changes in energy use among both consumers
and producers to reduce the impact of the regulatory requirements of
the final rule lead to the estimated social costs being somewhat less
than the total annualized compliance cost estimate of $43 million
(1998$). The primary reason for the lower social cost estimate is the
increase in electricity supply generated by existing unaffected
sources, which mostly offsets the impact of increased electricity
prices to consumers.
For more information on these impacts, please refer to the economic
impact analysis in the public docket.
D. What Are the Non-Air Health, Environmental and Energy Impacts?
The only energy requirement is a small increase in fuel consumption
resulting from back pressure caused by operating an oxidation catalyst
emission control device. This energy impact is small in comparison to
the costs of other impacts. There are no known non-air environmental or
health impacts as a result of the implementation of the final rule.
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order 12866 (58 FR 51735, October 4, 1993), we must
determine whether a regulatory action is ``significant'' and,
therefore, subject to review by the Office of Management and Budget
(OMB) and the requirements of the Executive Order. The Executive Order
defines ``significant regulatory action'' as one that is likely to
result in a rule that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
(2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs, or the rights and obligation of recipients
thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
Pursuant to the terms of Executive Order 12866, we have determined
that the final rule is a ``significant regulatory action'' within the
meaning of the Executive Order. As such, this action was submitted to
OMB for review. Changes made in response to OMB suggestions or
recommendations are included in the docket.
B. Paperwork Reduction Act
The information collection requirements in the final rule have been
submitted for approval to the Office of Management and Budget under the
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The information
requirements are not enforceable until OMB approves them.
The information requirements are based on notification,
recordkeeping, and reporting requirements in the NESHAP General
Provisions (40 CFR part 63, subpart A), which are mandatory for all
operators subject to national emission standards. These recordkeeping
and reporting requirements are specifically authorized by section 114
of the CAA (42 U.S.C. 7414). All information submitted to EPA pursuant
to the recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to Agency policies set
forth in 40 CFR part 2, subpart B.
The final rule will require maintenance inspections of the control
devices but will not require any notifications or reports beyond those
required by the General Provisions. The recordkeeping requirements
require only the specific information needed to determine compliance.
The annual monitoring, reporting, and recordkeeping burden for this
collection (averaged over the first 3 years after the effective date of
the final rule) is estimated to be 2,448 labor hours per year at a
total annual cost of $333,450. This estimate includes a one-time
performance test, semiannual excess emission reports, maintenance
inspections, notifications, and recordkeeping. Total capital/startup
costs associated with the monitoring requirements over the 3-year
period of the ICR are estimated at $22,500, with no operation and
maintenance costs.
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An Agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is
approved by OMB, the Agency will publish a technical amendment to 40
CFR part 9 in the Federal Register to display the OMB control number
for the approved information collection requirements contained in this
final rule.
C. Regulatory Flexibility Act
The EPA has determined that it is not necessary to prepare a
regulatory flexibility analysis in connection with the final rule. The
EPA has also determined that the final rule will not have a significant
economic impact on a substantial number of small entities.
For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business whose parent
company has fewer than 100 or 1,000 employees, or fewer than 4 billion
kW-hr per year of electricity usage, depending on size definition for
the affected North American Industry Classification System (NAICS)
code; (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. It should be noted that small
entities in 6 NAICS codes are affected by the final rule, and the small
[[Page 10535]]
business definition applied to each industry by NAICS code is that
listed in the Small Business Administration (SBA) size standards (13
CFR 121).
After considering the economic impacts of today's final rule on
small entities, EPA has concluded that this action will not have a
significant economic impact on a substantial number of small entities.
We have determined, based on the existing combustion turbines
inventory, that 29 small entities out of 300 in the industries impacted
by the final rule may be affected. None of these small entities will
incur control costs associated with the final rule, but will incur
monitoring, recordkeeping, and reporting costs and the costs of
performance testing. These 29 small entities own 51 affected turbines
in the existing combustion turbines inventory, which represents 2.5
percent of the existing turbines overall. Of these entities, 22 of
these entities are small communities and 7 are affected small firms.
None of the 29 affected small entities are estimated to have compliance
costs that exceed one-half of 1 percent of their revenues. The median
compliance costs to affected small entities is 0.07 percent of sales.
In addition, the final rule is likely to also increase profits at the
many small firms and increase revenues for the many small communities
using combustion turbines that are not affected by the final rule as a
result of the very slight increase in market prices.
It should be noted that it is likely that the ongoing deregulation
of the electric power industry across the nation should minimize the
rule's impacts on small entities. Increased competition in the electric
power industry is forecasted to decrease the market price for wholesale
electric power. It is likely that open access to the grid and lower
market prices for electricity will make it less attractive for local
communities to purchase and operate new combustion turbines. For more
information on the results of the analysis of small entity impacts,
please refer to the economic impact analysis in the docket.
Although the final rule will not have a significant economic impact
on a substantial number of small entities, EPA nonetheless has tried to
reduce the impact of the final rule on small entities. In the final
rule, the Agency is applying the minimum level of control and the
minimum level of monitoring, recordkeeping, and reporting to affected
sources allowed by the Clean Air Act. Existing stationary combustion
turbines have no emission requirements. In addition, as mentioned
earlier in the preamble, new turbines with capacities under 1.0 MW are
not subject to the final rule. This provision should reduce the level
of small entity impacts.
D. Unfunded Mandates Reform Act of 1995
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, we
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
1 year. Before promulgating a rule for which a written statement is
needed, section 205 of the UMRA generally requires us 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 us 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 we establish any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, we must develop a small
government agency plan under section 203 of the UMRA. 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 regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
The EPA has determined that the final rule contains a Federal
mandate that will not result in expenditures of $100 million or more
for State, local, and tribal governments, in the aggregate, or the
private sector in any 1 year. The highest cost in any 1 year is less
than $43 million. Thus, today's rule is not subject to the requirements
of sections 202 and 205 of the UMRA.
Although not required by the UMRA, we have consulted with State and
local air pollution control officials. We also have held meetings on
the rule with many of the stakeholders from numerous individual
companies, environmental groups, consultants and vendors, labor unions,
and other interested parties. We have added materials to the Air docket
to document those meetings.
In addition, we have determined that the final rule contains no
regulatory requirements that might significantly or uniquely affect
small governments. Therefore, today's rule is not subject to the
requirements of section 203 of the UMRA.
E. Executive Order 13132: Federalism
Executive Order 13132 (64 FR 43255, August 10, 1999) requires us 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'' are defined in the Executive Order to include
regulations that have ``substantial direct effects on the States, on
the relationship between the national government and the States, or on
the distribution of power and responsibilities among the various levels
of government.''
The final 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 Executive Order 13132. The final rule primarily affects
private industry, and does not impose significant economic costs on
State or local governments. Thus, Executive Order 13132 does not apply
to the final rule.
Although not required by Executive Order 13132, we consulted with
representatives of State and local governments to enable them to
provide meaningful and timely input into the development of the final
rule. This consultation took place during the ICCR committee meetings
where members representing State and local governments participated in
developing recommendations for EPA's combustion-related rules,
including the final rule. The concerns raised by representatives of
State and local governments were considered during the development of
the final rule.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175 (65 FR 67249, November 6, 2000) requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by tribal officials in the development of
[[Page 10536]]
regulatory policies that have tribal implications.'' ``Policies that
have tribal implications'' is defined in the Executive Order to include
regulations that have ``substantial direct effects on one or more
Indian tribes, on the relationship between the Federal government and
the Indian tribes, or on the distribution of power and responsibilities
between the Federal government and Indian tribes.''
The final rule does not have tribal implications. It will not have
substantial direct effects on tribal governments, on the relationship
between the Federal government and Indian tribes, or on the
distribution of power and responsibilities between the Federal
government and Indian tribes, as specified in Executive Order 13175.
Thus, Executive Order 13175 does not apply to the final rule.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any
rule that: (1) Is determined to be ``economically significant'' as
defined under Executive Order 12866, and (2) concerns an environmental
health or safety risk that we have reason to believe may have a
disproportionate effect on children. If the regulatory action meets
both criteria, we must evaluate the environmental health or safety
effects of the planned rule on children, and explain why the planned
regulation is preferable to other potentially effective and reasonably
feasible alternatives.
We interpret Executive Order 13045 as applying only to those
regulatory actions that are based on health or safety risks, such that
the analysis required under section 5-501 of the Executive Order has
the potential to influence the regulation. The final rule is not
subject to Executive Order 13045 because it is based on technology
performance and not on health or safety risks.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This rule is not a ``significant energy action'' as defined in
Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'' (66 Fed.
Reg. 28355 (May 22, 2001)) because it is not likely to have a
significant adverse effect on the supply, distribution, or use of
energy. The basis for this determination is provided below.
The increase in petroleum product output, which includes increases
in fuel production, is estimated at 0.013 percent, or about 2,003
barrels per day based on 2000 U.S. fuel production nationwide. The
reduction in coal production is estimated at 0.00007 percent, or about
7,936 short tons per year based on 2000 U.S. coal production
nationwide. The reduction in electricity output is estimated at 0.083
percent, or about 20.4 billion kilowatt-hours per year based on 2000
U.S. electricity production nationwide. Production of natural gas is
expected to increase by 11.7 million cubic feet (ft3) per
day. The maximum of all energy price increases, which include increases
in natural gas prices as well as those for petroleum products, coal,
and electricity, is estimated to be the 0.71 percent increase in peak-
load electricity rates nationwide. Energy distribution costs may
increase by roughly no more than the same amount as electricity rates.
We expect that there will be no discernable impact on the import of
foreign energy supplies, and no other adverse outcomes are expected to
occur with regards to energy supplies. Also, the increase in cost of
energy production should be minimal given the very small increase in
fuel consumption resulting from back pressure related to operation of
oxidation catalyst emission control devices. All of the estimates
presented above account for some passthrough of costs to consumers as
well as the direct cost impact to producers. For more information on
these estimated energy effects, please refer to the economic impact
analysis for the final rule. This analysis is available in the public
docket.
No new combustion turbines with a capacity of less than 1.0 MW will
be affected. Also, the control level applied to affected new combustion
turbines is the minimum that can be applied consistent with the
provisions of the Clean Air Act.
Therefore, we conclude that the final rule when implemented will
not have a significant adverse effect on the supply, distribution, or
use of energy.
I. National Technology Transfer and Advancement Act
As noted in the proposed rule, section 12(d) of the National
Technology Transfer and Advancement Act (NTTAA) of 1995 (Public Law No.
104-113; 15 U.S.C. 272 note) directs the EPA to use voluntary consensus
standards in their regulatory and procurement 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, business practices)
developed or adopted by one or more voluntary consensus bodies. The
NTTAA directs EPA to provide Congress, through annual reports to the
Office of Management and Budget (OMB), with explanations when an agency
does not use available and applicable voluntary consensus standards.
The final rule involves technical standards. The EPA cites the
following standards in the final rule: EPA Methods 1, 1A, 3A, 3B, 4,
and 320. Consistent with the NTTAA, EPA conducted searches to identify
voluntary consensus standards in addition to these EPA methods. No
applicable voluntary consensus standards were identified for EPA Method
1A. The search and review results have been documented and are placed
in the docket (Docket ID No. OAR-2002-0060 (A-95-51)) for the final
rule.
The search for emissions measurement procedures identified six
voluntary consensus standards. The EPA determined that five of these
six standards identified for measuring emissions of the HAP or
surrogates subject to emission standards in the final rule were
impractical alternatives to EPA test methods for the purposes of the
rule. Therefore, EPA does not intend to adopt these standards for this
purpose. (See Docket ID No. OAR-2002-0060 (A-95-51) for further
information on the methods.)
The voluntary consensus standard ASTM D6348-03, ``Standard Test
Method for Determination of Gaseous Compounds by Extractive Direct
Interface Fourier Transform Infrared (FTIR) Spectroscopy,'' is an
acceptable alternative to EPA Method 320 for formaldehyde measurement
provided that, in ASTM D6348-03 Annex A5 (Analyte Spiking Technique),
the percent R must be greater than or equal to 70 and less than or
equal to 130.
Section 63.6120 and Table 3 to subpart YYYY of the final rule list
the EPA testing methods included in the regulation. Under Sec. Sec.
63.7(f) and 63.8(f) of subpart A of the General Provisions, a source
may apply to EPA for permission to use alternative test methods or
alternative monitoring requirements in place of any of the EPA testing
methods, performance specifications, or procedures.
J. Congressional Review Act
The Congressional Review Act, 5 U.S.C. section 801 et seq., as
added by the Small Business Regulatory Enforcement Fairness Act of
1996, generally provides that before a rule may take effect, the agency
promulgating the rule must submit a
[[Page 10537]]
rule report, which includes a copy of the rule, to each House of the
Congress and to the Comptroller General of the United States. The EPA
will submit a report containing today's final rule and other required
information to the U.S. Senate, the U.S. House of Representatives, and
the comptroller General of the United States prior to publication of
the rule in the Federal Register. This action is not a ``major rule''
as defined by 5 U.S.C. 804(2). The final rule will be effective on
March 5, 2004.
List of Subjects in 40 CFR Part 63
Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances, Intergovernmental
relations, Reporting and recordkeeping requirements.
Dated: August 29, 2003.
Marianne Lamont Horinko,
Acting Administrator.
0
For the reasons set out in the preamble, title 40, chapter I, part 63
of the Code of the Federal Regulations is amended as follows:
PART 63--[AMENDED]
0
1. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
0
2. Part 63 is amended by adding subpart YYYY to read as follows:
Subpart YYYY--National Emission Standards for Hazardous Air
Pollutants for Stationary Combustion Turbines
Sec.
What This Subpart Covers
63.6080 What is the purpose of subpart YYYY?
63.6085 Am I subject to this subpart?
63.6090 What parts of my plant does this subpart cover?
63.6092 Are duct burners and waste heat recovery units covered by
subpart YYYY?
63.6095 When do I have to comply with this subpart?
Emission and Operating Limitations
63.6100 What emission and operating limitations must I meet?
General Compliance Requirements
63.6105 What are my general requirements for complying with this
subpart?
Testing and Initial Compliance Requirements
63.6110 By what date must I conduct the initial performance tests or
other initial compliance demonstrations?
63.6115 When must I conduct subsequent performance tests?
63.6120 What performance tests and other procedures must I use?
63.6125 What are my monitor installation, operation, and maintenance
requirements?
63.6130 How do I demonstrate initial compliance with the emission
and operating limitations?
Continuous Compliance Requirements
63.6135 How do I monitor and collect data to demonstrate continuous
compliance?
63.6140 How do I demonstrate continuous compliance with the emission
and operating limitations?
Notifications, Reports, and Records
63.6145 What notifications must I submit and when?
63.6150 What reports must I submit and when?
63.6155 What records must I keep?
63.6160 In what form and how long must I keep my records?
Other Requirements and Information
63.6165 What parts of the General Provisions apply to me?
63.6170 Who implements and enforces this subpart?
63.6175 What definitions apply to this subpart?
Tables to Subpart YYYY of Part 63
Table 1 to Subpart YYYY of Part 63.--Emission Limitations
Table 2 to Subpart YYYY of Part 63.--Operating Limitations
Table 3 to Subpart YYYY of Part 63.--Requirements for Performance
Tests and Initial Compliance Demonstrations
Table 4 to Subpart YYYY of Part 63.--Initial Compliance with
Emission Limitations
Table 5 to Subpart YYYY of Part 63.--Continuous Compliance with
Operating Limitations
Table 6 to Subpart YYYY of Part 63.--Requirements for Reports
Table 7 to Subpart YYYY of Part 63.--Applicability of General
Provisions to Subpart YYYY
What This Subpart Covers
Sec. 63.6080 What is the purpose of subpart YYYY?
Subpart YYYY establishes national emission limitations and
operating limitations for hazardous air pollutants (HAP) emissions from
stationary combustion turbines located at major sources of HAP
emissions, and requirements to demonstrate initial and continuous
compliance with the emission and operating limitations.
Sec. 63.6085 Am I subject to this subpart?
You are subject to this subpart if you own or operate a stationary
combustion turbine located at a major source of HAP emissions.
(a) Stationary combustion turbine means all equipment, including
but not limited to the turbine, the fuel, air, lubrication and exhaust
gas systems, control systems (except emissions control equipment), and
any ancillary components and sub-components comprising any simple cycle
stationary combustion turbine, any regenerative/recuperative cycle
stationary combustion turbine, the combustion turbine portion of any
stationary cogeneration cycle combustion system, or the combustion
turbine portion of any stationary combined cycle steam/electric
generating system. Stationary means that the combustion turbine is not
self propelled or intended to be propelled while performing its
function, although it may be mounted on a vehicle for portability or
transportability. Stationary combustion turbines covered by this
subpart include simple cycle stationary combustion turbines,
regenerative/recuperative cycle stationary combustion turbines,
cogeneration cycle stationary combustion turbines, and combined cycle
stationary combustion turbines. Stationary combustion turbines subject
to this subpart do not include turbines located at a research or
laboratory facility, if research is conducted on the turbine itself and
the turbine is not being used to power other applications at the
research or laboratory facility.
(b) A major source of HAP emissions is a contiguous site under
common control that emits or has the potential to emit any single HAP
at a rate of 10 tons (9.07 megagrams) or more per year or any
combination of HAP at a rate of 25 tons (22.68 megagrams) or more per
year, except that for oil and gas production facilities, a major source
of HAP emissions is determined for each surface site.
Sec. 63.6090 What parts of my plant does this subpart cover?
This subpart applies to each affected source.
(a) Affected source. An affected source is any existing, new, or
reconstructed stationary combustion turbine located at a major source
of HAP emissions.
(1) Existing stationary combustion turbine. A stationary combustion
turbine is existing if you commenced construction or reconstruction of
the stationary combustion turbine on or before January 14, 2003. A
change in ownership of an existing stationary combustion turbine does
not make that stationary combustion turbine a new or reconstructed
stationary combustion turbine.
(2) New stationary combustion turbine. A stationary combustion
turbine is new if you commenced construction of the stationary
[[Page 10538]]
combustion turbine after January 14, 2003.
(3) Reconstructed stationary combustion turbine. A stationary
combustion turbine is reconstructed if you meet the definition of
reconstruction in Sec. 63.2 of subpart A of this part and
reconstruction is commenced after January 14, 2003.
(b) Subcategories with limited requirements.
(1) A new or reconstructed stationary combustion turbine located at
a major source which meets either of the following criteria does not
have to meet the requirements of this subpart and of subpart A of this
part except for the initial notification requirements of Sec.
63.6145(d):
(i) The stationary combustion turbine is an emergency stationary
combustion turbine; or
(ii) The stationary combustion turbine is located on the North
Slope of Alaska.
(2) A stationary combustion turbine which burns landfill gas or
digester gas equivalent to 10 percent or more of the gross heat input
on an annual basis, or a stationary combustion turbine where gasified
municipal solid waste (MSW) is used to generate 10 percent or more of
the gross heat input on an annual basis does not have to meet the
requirements of this subpart except for:
(i) The initial notification requirements of Sec. 63.6145(d); and
(ii) Additional monitoring and reporting requirements as provided
in Sec. 63.6125(c) and Sec. 63.6150.
(3) An existing, new, or reconstructed stationary combustion
turbine with a rated peak power output of less than 1.0 megawatt (MW)
at International Organization for Standardization (ISO) standard day
conditions, which is located at a major source, does not have to meet
the requirements of this subpart and of subpart A of this part. This
determination applies to the capacities of individual combustion
turbines, whether or not an aggregated group of combustion turbines has
a common add-on air pollution control device. No initial notification
is necessary, even if the unit appears to be subject to other
requirements for initial notification. For example, a 0.75 MW emergency
turbine would not have to submit an initial notification.
(4) Existing stationary combustion turbines in all subcategories do
not have to meet the requirements of this subpart and of subpart A of
this part. No initial notification is necessary for any existing
stationary combustion turbine, even if a new or reconstructed turbine
in the same category would require an initial notification.
(5) Combustion turbine engine test cells/stands do not have to meet
the requirements of this subpart but may have to meet the requirements
of subpart A of this part if subject to another subpart. No initial
notification is necessary, even if the unit appears to be subject to
other requirements for initial notification.
Sec. 63.6092 Are duct burners and waste heat recovery units covered
by subpart YYYY?
No, duct burners and waste heat recovery units are considered steam
generating units and are not covered under this subpart. In some cases,
it may be difficult to separately monitor emissions from the turbine
and duct burner, so sources are allowed to meet the required emission
limitations with their duct burners in operation.
Sec. 63.6095 When do I have to comply with this subpart?
(a) Affected sources. (1) If you start up a new or reconstructed
stationary combustion turbine which is a lean premix gas-fired
stationary combustion turbine, a lean premix oil-fired stationary
combustion turbine, a diffusion flame gas-fired stationary combustion
turbine, or a diffusion flame oil-fired stationary combustion turbine
as defined by this subpart on or before March 5, 2004, you must comply
with the emission limitations and operating limitations in this subpart
no later than March 5, 2004.
(2) If you start up a new or reconstructed stationary combustion
turbine which is a lean premix gas-fired stationary combustion turbine,
a lean premix oil-fired stationary combustion turbine, a diffusion
flame gas-fired stationary combustion turbine, or a diffusion flame
oil-fired stationary combustion turbine as defined by this subpart
after March 5, 2004, you must comply with the emission limitations and
operating limitations in this subpart upon startup of your affected
source.
(b) Area sources that become major sources. If your new or
reconstructed stationary combustion turbine is an area source that
increases its emissions or its potential to emit such that it becomes a
major source of HAP, it must be in compliance with any applicable
requirements of this subpart when it becomes a major source.
(c) You must meet the notification requirements in Sec. 63.6145
according to the schedule in Sec. 63.6145 and in 40 CFR part 63,
subpart A.
Emission and Operating Limitations
Sec. 63.6100 What emission and operating limitations must I meet?
For each new or reconstructed stationary combustion turbine which
is a lean premix gas-fired stationary combustion turbine, a lean premix
oil-fired stationary combustion turbine, a diffusion flame gas-fired
stationary combustion turbine, or a diffusion flame oil-fired
stationary combustion turbine as defined by this subpart, you must
comply with the emission limitations and operating limitations in Table
1 and Table 2 of this subpart.
General Compliance Requirements
Sec. 63.6105 What are my general requirements for complying with this
subpart?
(a) You must be in compliance with the emission limitations and
operating limitations which apply to you at all times except during
startup, shutdown, and malfunctions.
(b) If you must comply with emission and operating limitations, you
must operate and maintain your stationary combustion turbine, oxidation
catalyst emission control device or other air pollution control
equipment, and monitoring equipment in a manner consistent with good
air pollution control practices for minimizing emissions at all times
including during startup, shutdown, and malfunction.
Testing and Initial Compliance Requirements
Sec. 63.6110 By what date must I conduct the initial performance
tests or other initial compliance demonstrations?
(a) You must conduct the initial performance tests or other initial
compliance demonstrations in Table 4 of this subpart that apply to you
within 180 calendar days after the compliance date that is specified
for your stationary combustion turbine in Sec. 63.6095 and according
to the provisions in Sec. 63.7(a)(2).
(b) An owner or operator is not required to conduct an initial
performance test to determine outlet formaldehyde concentration on
units for which a performance test has been previously conducted, but
the test must meet all of the conditions described in paragraphs (b)(1)
through (b)(5) of this section.
(1) The test must have been conducted using the same methods
specified in this subpart, and these methods must have been followed
correctly.
(2) The test must not be older than 2 years.
[[Page 10539]]
(3) The test must be reviewed and accepted by the Administrator.
(4) Either no process or equipment changes must have been made
since the test was performed, or the owner or operator must be able to
demonstrate that the results of the performance test, with or without
adjustments, reliably demonstrate compliance despite process or
equipment changes.
(5) The test must be conducted at any load condition within plus or
minus 10 percent of 100 percent load.
Sec. 63.6115 When must I conduct subsequent performance tests?
Subsequent performance tests must be performed on an annual basis
as specified in Table 3 of this subpart.
Sec. 63.6120 What performance tests and other procedures must I use?
(a) You must conduct each performance test in Table 3 of this
subpart that applies to you.
(b) Each performance test must be conducted according to the
requirements of the General Provisions at Sec. 63.7(e)(1) and under
the specific conditions in Table 2 of this subpart.
(c) Do not conduct performance tests or compliance evaluations
during periods of startup, shutdown, or malfunction. Performance tests
must be conducted at high load, defined as 100 percent plus or minus 10
percent.
(d) You must conduct three separate test runs for each performance
test, and each test run must last at least 1 hour.
(e) If your stationary combustion turbine is not equipped with an
oxidation catalyst, you must petition the Administrator for operating
limitations that you will monitor to demonstrate compliance with the
formaldehyde emission limitation in Table 1. You must measure these
operating parameters during the initial performance test and
continuously monitor thereafter. Alternatively, you may petition the
Administrator for approval of no additional operating limitations. If
you submit a petition under this section, you must not conduct the
initial performance test until after the petition has been approved or
disapproved by the Administrator.
(f) If your stationary combustion turbine is not equipped with an
oxidation catalyst and you petition the Administrator for approval of
additional operating limitations to demonstrate compliance with the
formaldehyde emission limitation in Table 1, your petition must include
the following information described in paragraphs (f)(1) through (5) of
this section.
(1) Identification of the specific parameters you propose to use as
additional operating limitations;
(2) A discussion of the relationship between these parameters and
HAP emissions, identifying how HAP emissions change with changes in
these parameters and how limitations on these parameters will serve to
limit HAP emissions;
(3) A discussion of how you will establish the upper and/or lower
values for these parameters which will establish the limits on these
parameters in the operating limitations;
(4) A discussion identifying the methods you will use to measure
and the instruments you will use to monitor these parameters, as well
as the relative accuracy and precision of these methods and
instruments; and
(5) A discussion identifying the frequency and methods for
recalibrating the instruments you will use for monitoring these
parameters.
(g) If you petition the Administrator for approval of no additional
operating limitations, your petition must include the information
described in paragraphs (g)(1) through (7) of this section.
(1) Identification of the parameters associated with operation of
the stationary combustion turbine and any emission control device which
could change intentionally (e.g., operator adjustment, automatic
controller adjustment, etc.) or unintentionally (e.g., wear and tear,
error, etc.) on a routine basis or over time;
(2) A discussion of the relationship, if any, between changes in
the parameters and changes in HAP emissions;
(3) For the parameters which could change in such a way as to
increase HAP emissions, a discussion of why establishing limitations on
the parameters is not possible;
(4) For the parameters which could change in such a way as to
increase HAP emissions, a discussion of why you could not establish
upper and/or lower values for the parameters which would establish
limits on the parameters as operating limitations;
(5) For the parameters which could change in such a way as to
increase HAP emissions, a discussion identifying the methods you could
use to measure them and the instruments you could use to monitor them,
as well as the relative accuracy and precision of the methods and
instruments;
(6) For the parameters, a discussion identifying the frequency and
methods for recalibrating the instruments you could use to monitor
them; and
(7) A discussion of why, from your point of view, it is infeasible,
unreasonable or unnecessary to adopt the parameters as operating
limitations.
Sec. 63.6125 What are my monitor installation, operation, and
maintenance requirements?
(a) If you are operating a stationary combustion turbine that is
required to comply with the formaldehyde emission limitation and you
use an oxidation catalyst emission control device, you must monitor on
a continuous basis your catalyst inlet temperature in order to comply
with the operating limitations in Table 2 and as specified in Table 5
of this subpart.
(b) If you are operating a stationary combustion turbine that is
required to comply with the formaldehyde emission limitation and you
are not using an oxidation catalyst, you must continuously monitor any
parameters specified in your approved petition to the Administrator, in
order to comply with the operating limitations in Table 2 and as
specified in Table 5 of this subpart.
(c) If you are operating a stationary combustion turbine which
fires landfill gas or digester gas equivalent to 10 percent or more of
the gross heat input on an annual basis, or a stationary combustion
turbine where gasified MSW is used to generate 10 percent or more of
the gross heat input on an annual basis, you must monitor and record
your fuel usage daily with separate fuel meters to measure the
volumetric flow rate of each fuel. In addition, you must operate your
turbine in a manner which minimizes HAP emissions.
(d) If you are operating a lean premix gas-fired stationary
combustion turbine or a diffusion flame gas-fired stationary combustion
turbine as defined by this subpart, and you use any quantity of
distillate oil to fire any new or existing stationary combustion
turbine which is located at the same major source, you must monitor and
record your distillate oil usage daily for all new and existing
stationary combustion turbines located at the major source with a non-
resettable hour meter to measure the number of hours that distillate
oil is fired.
Sec. 63.6130 How do I demonstrate initial compliance with the
emission and operating limitations?
(a) You must demonstrate initial compliance with each emission and
operating limitation that applies to you according to Table 4 of this
subpart.
(b) You must submit the Notification of Compliance Status
containing results of the initial compliance demonstration according to
the requirements in Sec. 63.6145(f).
[[Page 10540]]
Continuous Compliance Requirements
Sec. 63.6135 How do I monitor and collect data to demonstrate
continuous compliance?
(a) Except for monitor malfunctions, associated repairs, and
required quality assurance or quality control activities (including, as
applicable, calibration checks and required zero and span adjustments
of the monitoring system), you must conduct all parametric monitoring
at all times the stationary combustion turbine is operating.
(b) Do not use data recorded during monitor malfunctions,
associated repairs, and required quality assurance or quality control
activities for meeting the requirements of this subpart, including data
averages and calculations. You must use all the data collected during
all other periods in assessing the performance of the control device or
in assessing emissions from the new or reconstructed stationary
combustion turbine.
Sec. 63.6140 How do I demonstrate continuous compliance with the
emission and operating limitations?
(a) You must demonstrate continuous compliance with each emission
limitation and operating limitation in Table 1 and Table 2 of this
subpart according to methods specified in Table 5 of this subpart.
(b) You must report each instance in which you did not meet each
emission imitation or operating limitation. You must also report each
instance in which you did not meet the requirements in Table 7 of this
subpart that apply to you. These instances are deviations from the
emission and operating limitations in this subpart. These deviations
must be reported according to the requirements in Sec. 63.6150.
(c) Consistent with Sec. Sec. 63.6(e) and 63.7(e)(1), deviations
that occur during a period of startup, shutdown, and malfunction are
not violations if you have operated your stationary combustion turbine
in full conformity with all provisions of your startup, shutdown, and
malfunction plan, and you have otherwise satisfied the general duty to
minimize emissions established by Sec. 63.6(e)(1)(i).
Notifications, Reports, and Records
Sec. 63.6145 What notifications must I submit and when?
(a) You must submit all of the notifications in Sec. Sec. 63.7(b)
and (c), 63.8(e), 63.8(f)(4), and 63.9(b) and (h) that apply to you by
the dates specified.
(b) As specified in Sec. 63.9(b)(2), if you start up your new or
reconstructed stationary combustion turbine before March 5, 2004, you
must submit an Initial Notification not later than 120 calendar days
after March 5, 2004.
(c) As specified in Sec. 63.9(b), if you start up your new or
reconstructed stationary combustion turbine on or after March 5, 2004,
you must submit an Initial Notification not later than 120 calendar
days after you become subject to this subpart.
(d) If you are required to submit an Initial Notification but are
otherwise not affected by the emission limitation requirements of this
subpart, in accordance with Sec. 63.6090(b), your notification must
include the information in Sec. 63.9(b)(2)(i) through (v) and a
statement that your new or reconstructed stationary combustion turbine
has no additional emission limitation requirements and must explain the
basis of the exclusion (for example, that it operates exclusively as an
emergency stationary combustion turbine).
(e) If you are required to conduct an initial performance test, you
must submit a notification of intent to conduct an initial performance
test at least 60 calendar days before the initial performance test is
scheduled to begin as required in Sec. 63.7(b)(1).
(f) If you are required to comply with the emission limitation for
formaldehyde, you must submit a Notification of Compliance Status
according to Sec. 63.9(h)(2)(ii). For each performance test required
to demonstrate compliance with the emission limitation for
formaldehyde, you must submit the Notification of Compliance Status,
including the performance test results, before the close of business on
the 60th calendar day following the completion of the performance test.
Sec. 63.6150 What reports must I submit and when?
(a) Anyone who owns or operates a stationary combustion turbine
which must meet the emission limitation for formaldehyde must submit a
semiannual compliance report according to Table 6 of this subpart. The
semiannual compliance report must contain the information described in
paragraphs (a)(1) through (a)(4) of this section. The semiannual
compliance report must be submitted by the dates specified in
paragraphs (b)(1) through (b)(5) of this section, unless the
Administrator has approved a different schedule.
(1) Company name and address.
(2) Statement by a responsible official, with that official's name,
title, and signature, certifying the accuracy of the content of the
report.
(3) Date of report and beginning and ending dates of the reporting
period.
(4) For each deviation from an emission limitation, the compliance
report must contain the information in paragraphs (a)(4)(i) through
(a)(4)(iii) of this section.
(i) The total operating time of each stationary combustion turbine
during the reporting period.
(ii) Information on the number, duration, and cause of deviations
(including unknown cause, if applicable), as applicable, and the
corrective action taken.
(iii) Information on the number, duration, and cause for monitor
downtime incidents (including unknown cause, if applicable, other than
downtime associated with zero and span and other daily calibration
checks).
(b) Dates of submittal for the semiannual compliance report are
provided in (b)(1) through (b)(5) of this section.
(1) The first semiannual compliance report must cover the period
beginning on the compliance date specified in Sec. 63.6095 and ending
on June 30 or December 31, whichever date is the first date following
the end of the first calendar half after the compliance date specified
in Sec. 63.6095.
(2) The first semiannual compliance report must be postmarked or
delivered no later than July 31 or January 31, whichever date follows
the end of the first calendar half after the compliance date that is
specified in Sec. 63.6095.
(3) Each subsequent semiannual compliance report must cover the
semiannual reporting period from January 1 through June 30 or the
semiannual reporting period from July 1 through December 31.
(4) Each subsequent semiannual compliance report must be postmarked
or delivered no later than July 31 or January 31, whichever date is the
first date following the end of the semiannual reporting period.
(5) For each stationary combustion turbine that is subject to
permitting regulations pursuant to 40 CFR part 70 or 71, and if the
permitting authority has established the date for submitting annual
reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance
reports according to the dates the permitting authority has established
instead of according to the dates in paragraphs (b)(1) through (4) of
this section.
(c) If you are operating as a stationary combustion turbine which
fires landfill gas or digester gas equivalent to 10 percent or more of
the gross heat input on an annual basis, or a stationary
[[Page 10541]]
combustion turbine where gasified MSW is used to generate 10 percent or
more of the gross heat input on an annual basis, you must submit an
annual report according to Table 6 of this subpart by the date
specified unless the Administrator has approved a different schedule,
according to the information described in paragraphs (d)(1) through (5)
of this section. You must report the data specified in (c)(1) through
(c)(3) of this section.
(1) Fuel flow rate of each fuel and the heating values that were
used in your calculations. You must also demonstrate that the
percentage of heat input provided by landfill gas, digester gas, or
gasified MSW is equivalent to 10 percent or more of the total fuel
consumption on an annual basis.
(2) The operating limits provided in your federally enforceable
permit, and any deviations from these limits.
(3) Any problems or errors suspected with the meters.
(d) Dates of submittal for the annual report are provided in (d)(1)
through (d)(5) of this section.
(1) The first annual report must cover the period beginning on the
compliance date specified in Sec. 63.6095 and ending on December 31.
(2) The first annual report must be postmarked or delivered no
later than January 31.
(3) Each subsequent annual report must cover the annual reporting
period from January 1 through December 31.
(4) Each subsequent annual report must be postmarked or delivered
no later than January 31.
(5) For each stationary combustion turbine that is subject to
permitting regulations pursuant to 40 CFR part 70 or 71, and if the
permitting authority has established the date for submitting annual
reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance
reports according to the dates the permitting authority has established
instead of according to the dates in paragraphs (d)(1) through (4) of
this section.
(e) If you are operating a lean premix gas-fired stationary
combustion turbine or a diffusion flame gas-fired stationary combustion
turbine as defined by this subpart, and you use any quantity of
distillate oil to fire any new or existing stationary combustion
turbine which is located at the same major source, you must submit an
annual report according to Table 6 of this subpart by the date
specified unless the Administrator has approved a different schedule,
according to the information described in paragraphs (d)(1) through (5)
of this section. You must report the data specified in (e)(1) through
(e)(3) of this section.
(1) The number of hours distillate oil was fired by each new or
existing stationary combustion turbine during the reporting period.
(2) The operating limits provided in your federally enforceable
permit, and any deviations from these limits.
(3) Any problems or errors suspected with the meters.
Sec. 63.6155 What records must I keep?
(a) You must keep the records as described in paragraphs (a)(1)
through (5).
(1) A copy of each notification and report that you submitted to
comply with this subpart, including all documentation supporting any
Initial Notification or Notification of Compliance Status that you
submitted, according to the requirements in Sec. 63.10(b)(2)(xiv).
(2) Records of performance tests and performance evaluations as
required in Sec. 63.10(b)(2)(viii).
(3) Records of the occurrence and duration of each startup,
shutdown, or malfunction as required in Sec. 63.10(b)(2)(i).
(4) Records of the occurrence and duration of each malfunction of
the air pollution control equipment, if applicable, as required in
Sec. 63.10(b)(2)(ii).
(5) Records of all maintenance on the air pollution control
equipment as required in Sec. 63.10(b)(iii).
(b) If you are operating a stationary combustion turbine which
fires landfill gas, digester gas or gasified MSW equivalent to 10
percent or more of the gross heat input on an annual basis, or if you
are operating a lean premix gas-fired stationary combustion turbine or
a diffusion flame gas-fired stationary combustion turbine as defined by
this subpart, and you use any quantity of distillate oil to fire any
new or existing stationary combustion turbine which is located at the
same major source, you must keep the records of your daily fuel usage
monitors.
(c) You must keep the records required in Table 5 of this subpart
to show continuous compliance with each operating limitation that
applies to you.
Sec. 63.6160 In what form and how long must I keep my records?
(a) You must maintain all applicable records in such a manner that
they can be readily accessed and are suitable for inspection according
to Sec. 63.10(b)(1).
(b) As specified in Sec. 63.10(b)(1), you must keep each record
for 5 years following the date of each occurrence, measurement,
maintenance, corrective action, report, or record.
(c) You must retain your records of the most recent 2 years on site
or your records must be accessible on site. Your records of the
remaining 3 years may be retained off site.
Other Requirements and Information
Sec. 63.6165 What parts of the General Provisions apply to me?
Table 7 of this subpart shows which parts of the General Provisions
in Sec. 63.1 through 15 apply to you.
Sec. 63.6170 Who implements and enforces this subpart?
(a) This subpart is implemented and enforced by the U.S. EPA or a
delegated authority such as your State, local, or tribal agency. If the
EPA Administrator has delegated authority to your State, local, or
tribal agency, then that agency (as well as the U.S. EPA) has the
authority to implement and enforce this subpart. You should contact
your EPA Regional Office to find out whether this subpart is delegated
to your State, local, or tribal agency.
(b) In delegating implementation and enforcement authority of this
subpart to a State, local, or tribal agency under section 40 CFR part
63, subpart E, the authorities contained in paragraph (c) of this
section are retained by the EPA Administrator and are not transferred
to the State, local, or tribal agency.
(c) The authorities that will not be delegated to State, local, or
tribal agencies are:
(1) Approval of alternatives to the emission limitations or
operating limitations in Sec. 63.6100 under Sec. 63.6(g).
(2) Approval of major alternatives to test methods under Sec.
63.7(e)(2)(ii) and (f) and as defined in Sec. 63.90.
(3) Approval of major alternatives to monitoring under Sec.
63.8(f) and as defined in Sec. 63.90.
(4) Approval of major alternatives to recordkeeping and reporting
under Sec. 63.10(f) and as defined in Sec. 63.90.
(5) Approval of a performance test which was conducted prior to the
effective date of the rule to determine outlet formaldehyde
concentration, as specified in Sec. 63.6110(b).
Sec. 63.6175 What definitions apply to this subpart?
Terms used in this subpart are defined in the CAA; in 40 CFR 63.2,
the General Provisions of this part; and in this section:
Area source means any stationary source of HAP that is not a major
source as defined in this part.
Associated equipment as used in this subpart and as referred to in
section 112(n)(4) of the CAA, means equipment associated with an oil or
natural gas
[[Page 10542]]
exploration or production well, and includes all equipment from the
well bore to the point of custody transfer, except glycol dehydration
units, storage vessels with potential for flash emissions, combustion
turbines, and stationary reciprocating internal combustion engines.
CAA means the Clean Air Act (42 U.S.C. 7401 et seq., as amended by
Public Law 101-549, 104 Stat. 2399).
Cogeneration cycle stationary combustion turbine means any
stationary combustion turbine that recovers heat from the stationary
combustion turbine exhaust gases using an exhaust heat exchanger, such
as a heat recovery steam generator.
Combined cycle stationary combustion turbine means any stationary
combustion turbine that recovers heat from the stationary combustion
turbine exhaust gases using an exhaust heat exchanger to generate steam
for use in a steam turbine.
Combustion turbine engine test cells/stands means engine test
cells/stands, as defined in subpart PPPPP of this part, that test
stationary combustion turbines.
Compressor station means any permanent combination of compressors
that move natural gas at increased pressure from fields, in
transmission pipelines, or into storage.
Custody transfer means the transfer of hydrocarbon liquids or
natural gas: after processing and/or treatment in the producing
operations, or from storage vessels or automatic transfer facilities or
other such equipment, including product loading racks, to pipelines or
any other forms of transportation. For the purposes of this subpart,
the point at which such liquids or natural gas enters a natural gas
processing plant is a point of custody transfer.
Deviation means any instance in which an affected source subject to
this subpart, or an owner or operator of such a source:
(1) Fails to meet any requirement or obligation established by this
subpart, including but not limited to any emission limitation or
operating limitation;
(2) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit;
(3) Fails to meet any emission limitation or operating limitation
in this subpart during malfunction, regardless of whether or not such
failure is permitted by this subpart; or
(4) Fails to conform to any provision of the applicable startup,
shutdown, or malfunction plan, or to satisfy the general duty to
minimize emissions established by Sec. 63.6(e)(1)(i).
Diffusion flame gas-fired stationary combustion turbine means:
(1)(i) Each stationary combustion turbine which is equipped only to
fire gas using diffusion flame technology,
(ii) Each stationary combustion turbine which is equipped both to
fire gas using diffusion flame technology and to fire oil, during any
period when it is firing gas, and
(iii) Each stationary combustion turbine which is equipped both to
fire gas using diffusion flame technology and to fire oil, and is
located at a major source where all new, reconstructed, and existing
stationary combustion turbines fire oil no more than an aggregate total
of 1000 hours during the calendar year.
(2) Diffusion flame gas-fired stationary combustion turbines do not
include:
(i) Any emergency stationary combustion turbine,
(ii) Any stationary combustion turbine located on the North Slope
of Alaska, or
(iii) Any stationary combustion turbine burning landfill gas or
digester gas equivalent to 10 percent or more of the gross heat input
on an annual basis, or any stationary combustion turbine where gasified
MSW is used to generate 10 percent or more of the gross heat input on
an annual basis.
Diffusion flame oil-fired stationary combustion turbine means:
(1)(i) Each stationary combustion turbine which is equipped only to
fire oil using diffusion flame technology, and
(ii) Each stationary combustion turbine which is equipped both to
fire oil using diffusion flame technology and to fire gas, and is
located at a major source where all new, reconstructed, and existing
stationary combustion turbines fire oil more than an aggregate total of
1000 hours during the calendar year, during any period when it is
firing oil.
(2) Diffusion flame oil-fired stationary combustion turbines do not
include:
(i) Any emergency stationary combustion turbine, or
(ii) Any stationary combustion turbine located on the North Slope
of Alaska.
Diffusion flame technology means a configuration of a stationary
combustion turbine where fuel and air are injected at the combustor and
are mixed only by diffusion prior to ignition.
Digester gas means any gaseous by-product of wastewater treatment
typically formed through the anaerobic decomposition of organic waste
materials and composed principally of methane and CO2.
Distillate oil means any liquid obtained from the distillation of
petroleum with a boiling point of approximately 150 to 360 degrees
Celsius. One commonly used form is fuel oil number 2.
Emergency stationary combustion turbine means any stationary
combustion turbine that operates in an emergency situation. Examples
include stationary combustion turbines used to produce power for
critical networks or equipment (including power supplied to portions of
a facility) when electric power from the local utility is interrupted,
or stationary combustion turbines used to pump water in the case of
fire or flood, etc. Emergency stationary combustion turbines do not
include stationary combustion turbines used as peaking units at
electric utilities or stationary combustion turbines at industrial
facilities that typically operate at low capacity factors. Emergency
stationary combustion turbines may be operated for the purpose of
maintenance checks and readiness testing, provided that the tests are
required by the manufacturer, the vendor, or the insurance company
associated with the turbine. Required testing of such units should be
minimized, but there is no time limit on the use of emergency
stationary combustion turbines.
Glycol dehydration unit means a device in which a liquid glycol
(including, but not limited to, ethylene glycol, diethylene glycol, or
triethylene glycol) absorbent directly contacts a natural gas stream
and absorbs water in a contact tower or absorption column (absorber).
The glycol contacts and absorbs water vapor and other gas stream
constituents from the natural gas and becomes ``rich'' glycol. This
glycol is then regenerated in the glycol dehydration unit reboiler. The
``lean'' glycol is then recycled.
Hazardous air pollutant (HAP) means any air pollutant listed in or
pursuant to section 112(b) of the CAA.
ISO standard day conditions means 288 degrees Kelvin
(15C), 60 percent relative humidity and 101.3
kilopascals pressure.
Landfill gas means a gaseous by-product of the land application of
municipal refuse typically formed through the anaerobic decomposition
of waste materials and composed principally of methane and
CO2.
Lean premix gas-fired stationary combustion turbine means:
(1)(i) Each stationary combustion turbine which is equipped only to
fire gas using lean premix technology,
(ii) Each stationary combustion turbine which is equipped both to
fire gas using lean premix technology and to
[[Page 10543]]
fire oil, during any period when it is firing gas, and
(iii) Each stationary combustion turbine which is equipped both to
fire gas using lean premix technology and to fire oil, and is located
at a major source where all new, reconstructed, and existing stationary
combustion turbines fire oil no more than an aggregate total of 1000
hours during the calendar year.
(2) Lean premix gas-fired stationary combustion turbines do not
include:
(i) Any emergency stationary combustion turbine,
(ii) Any stationary combustion turbine located on the North Slope
of Alaska, or
(iii) Any stationary combustion turbine burning landfill gas or
digester gas equivalent to 10 percent or more of the gross heat input
on an annual basis, or any stationary combustion turbine where gasified
MSW is used to generate 10 percent or more of the gross heat input on
an annual basis.
Lean premix oil-fired stationary combustion turbine means:
(1)(i) Each stationary combustion turbine which is equipped only to
fire oil using lean premix technology, and
(ii) Each stationary combustion turbine which is equipped both to
fire oil using lean premix technology and to fire gas, and is located
at a major source where all new, reconstructed, and existing stationary
combustion turbines fire oil more than an aggregate total of 1000 hours
during the calendar year, during any period when it is firing oil.
(2) Lean premix oil-fired stationary combustion turbines do not
include:
(i) Any emergency stationary combustion turbine, or
(ii) Any stationary combustion turbine located on the North Slope
of Alaska.
Lean premix technology means a configuration of a stationary
combustion turbine where the air and fuel are thoroughly mixed to form
a lean mixture for combustion in the combustor. Mixing may occur before
or in the combustion chamber.
Major source, as used in this subpart, shall have the same meaning
as in Sec. 63.2, except that:
(1) Emissions from any oil or gas exploration or production well
(with its associated equipment (as defined in this section)) and
emissions from any pipeline compressor station or pump station shall
not be aggregated with emissions from other similar units, to determine
whether such emission points or stations are major sources, even when
emission points are in a contiguous area or under common control;
(2) For oil and gas production facilities, emissions from
processes, operations, or equipment that are not part of the same oil
and gas production facility, as defined in this section, shall not be
aggregated;
(3) For production field facilities, only HAP emissions from glycol
dehydration units, storage vessel with the potential for flash
emissions, combustion turbines and reciprocating internal combustion
engines shall be aggregated for a major source determination; and
(4) Emissions from processes, operations, and equipment that are
not part of the same natural gas transmission and storage facility, as
defined in this section, shall not be aggregated.
Malfunction means any sudden, infrequent, and not reasonably
preventable failure of air pollution control equipment, process
equipment, or a process to operate in a normal or usual manner which
causes or has the potential to cause the emission limitations in this
standard to be exceeded. Failures that are caused in part by poor
maintenance or careless operation are not malfunctions.
Municipal solid waste as used in this subpart is as defined in
Sec. 60.1465 of Subpart AAAA of 40 CFR Part 60, New Source Performance
Standards for Small Municipal Waste Combustion Units.
Natural gas means a naturally occurring mixture of hydrocarbon and
non-hydrocarbon gases found in geologic formations beneath the Earth's
surface, of which the principal constituent is methane. May be field or
pipeline quality. For the purposes of this subpart, the definition of
natural gas includes similarly constituted fuels such as field gas,
refinery gas, and syngas.
Natural gas transmission means the pipelines used for the long
distance transport of natural gas (excluding processing). Specific
equipment used in natural gas transmission includes the land, mains,
valves, meters, boosters, regulators, storage vessels, dehydrators,
compressors, and their driving units and appurtenances, and equipment
used transporting gas from a production plant, delivery point of
purchased gas, gathering system, storage area, or other wholesale
source of gas to one or more distribution area(s).
Natural gas transmission and storage facility means any grouping of
equipment where natural gas is processed, compressed, or stored prior
to entering a pipeline to a local distribution company or (if there is
no local distribution company) to a final end user. Examples of a
facility for this source category are: an underground natural gas
storage operation; or a natural gas compressor station that receives
natural gas via pipeline, from an underground natural gas storage
operation, or from a natural gas processing plant. The emission points
associated with these phases include, but are not limited to, process
vents. Processes that may have vents include, but are not limited to,
dehydration and compressor station engines. Facility, for the purpose
of a major source determination, means natural gas transmission and
storage equipment that is located inside the boundaries of an
individual surface site (as defined in this section) and is connected
by ancillary equipment, such as gas flow lines or power lines.
Equipment that is part of a facility will typically be located within
close proximity to other equipment located at the same facility.
Natural gas transmission and storage equipment or groupings of
equipment located on different gas leases, mineral fee tracts, lease
tracts, subsurface unit areas, surface fee tracts, or surface lease
tracts shall not be considered part of the same facility.
North Slope of Alaska means the area north of the Arctic Circle
(latitude 66.5 degrees North).
Oil and gas production facility as used in this subpart means any
grouping of equipment where hydrocarbon liquids are processed, upgraded
(i.e., remove impurities or other constituents to meet contract
specifications), or stored prior to the point of custody transfer; or
where natural gas is processed, upgraded, or stored prior to entering
the natural gas transmission and storage source category. For purposes
of a major source determination, facility (including a building,
structure, or installation) means oil and natural gas production and
processing equipment that is located within the boundaries of an
individual surface site as defined in this section. Equipment that is
part of a facility will typically be located within close proximity to
other equipment located at the same facility. Pieces of production
equipment or groupings of equipment located on different oil and gas
leases, mineral fee tracts, lease tracts, subsurface or surface unit
areas, surface fee tracts, surface lease tracts, or separate surface
sites, whether or not connected by a road, waterway, power line or
pipeline, shall not be considered part of the same facility. Examples
of facilities in the oil and natural gas production source category
include, but are not limited to, well sites, satellite tank batteries,
central tank batteries, a compressor station that transports natural
gas to a natural gas processing plant, and natural gas processing
plants.
Oxidation catalyst emission control device means an emission
control
[[Page 10544]]
device that incorporates catalytic oxidation to reduce CO emissions.
Potential to emit means the maximum capacity of a stationary source
to emit a pollutant under its physical and operational design. Any
physical or operational limitation on the capacity of the stationary
source to emit a pollutant, including air pollution control equipment
and restrictions on hours of operation or on the type or amount of
material combusted, stored, or processed, shall be treated as part of
its design if the limitation or the effect it would have on emissions
is federally enforceable. For oil and natural gas production facilities
subject to subpart HH of this part, the potential to emit provisions in
Sec. 63.760(a) may be used. For natural gas transmission and storage
facilities subject to subpart HHH of this part, the maximum annual
facility gas throughput for storage facilities may be determined
according to Sec. 63.1270(a)(1) and the maximum annual throughput for
transmission facilities may be determined according to Sec.
63.1270(a)(2).
Production field facility means those oil and gas production
facilities located prior to the point of custody transfer.
Production well means any hole drilled in the earth from which
crude oil, condensate, or field natural gas is extracted.
Regenerative/recuperative cycle stationary combustion turbine means
any stationary combustion turbine that recovers heat from the
stationary combustion turbine exhaust gases using an exhaust heat
exchanger to preheat the combustion air entering the combustion chamber
of the stationary combustion turbine.
Research or laboratory facility means any stationary source whose
primary purpose is to conduct research and development into new
processes and products, where such source is operated under the close
supervision of technically trained personnel and is not engaged in the
manufacture of products for commercial sale in commerce, except in a de
minimis matter.
Simple cycle stationary combustion turbine means any stationary
combustion turbine that does not recover heat from the stationary
combustion turbine exhaust gases.
Stationary combustion turbine means all equipment, including but
not limited to the turbine, the fuel, air, lubrication and exhaust gas
systems, control systems (except emissions control equipment), and any
ancillary components and sub-components comprising any simple cycle
stationary combustion turbine, any regenerative/recuperative cycle
stationary combustion turbine, the combustion turbine portion of any
stationary cogeneration cycle combustion system, or the combustion
turbine portion of any stationary combined cycle steam/electric
generating system. Stationary means that the combustion turbine is not
self propelled or intended to be propelled while performing its
function. Stationary combustion turbines do not include turbines
located at a research or laboratory facility, if research is conducted
on the turbine itself and the turbine is not being used to power other
applications at the research or laboratory facility.
Storage vessel with the potential for flash emissions means any
storage vessel that contains a hydrocarbon liquid with a stock tank
gas-to-oil ratio equal to or greater than 0.31 cubic meters per liter
and an American Petroleum Institute gravity equal to or greater than 40
degrees and an actual annual average hydrocarbon liquid throughput
equal to or greater than 79,500 liters per day. Flash emissions occur
when dissolved hydrocarbons in the fluid evolve from solution when the
fluid pressure is reduced.
Surface site means any combination of one or more graded pad sites,
gravel pad sites, foundations, platforms, or the immediate physical
location upon which equipment is physically affixed.
Tables to Subpart YYYY of Part 63.
As stated in Sec. 63.6100, you must comply with the following
emission limitations:
Table 1 to Subpart YYYY of Part 63.--Emission Limitations
------------------------------------------------------------------------
For each new or reconstructed stationary
combustion turbine described in Sec. You must meet the following
63.6100 which is . . . emission limitations . . .
------------------------------------------------------------------------
1. a lean premix gas-fired stationary limit the concentration of
combustion turbine as defined in this formaldehyde to 91 ppbvd or
subpart, less at 15 percent O2.
2. a lean premix oil-fired stationary
combustion turbine as defined in this
subpart,
3. a diffusion flame gas-fired stationary
combustion turbine as defined in this
subpart, or
4. a diffusion flame oil-fired stationary
combustion turbine as defined in this
subpart.
------------------------------------------------------------------------
As stated in Sec. Sec. 63.6100 and 63.6140, you must comply
with the following operating limitations:
Table 2 to Subpart YYYY of Part 63.--Operating Limitations
------------------------------------------------------------------------
For . . . You must . . .
------------------------------------------------------------------------
1. each stationary combustion turbine maintain the 4-hour rolling
that is required to comply with the average of the catalyst inlet
emission limitation for formaldehyde temperature within the range
and is using an oxidation catalyst. suggested by the catalyst
manufacturer.
----------------------------------------
2. each stationary combustion turbine maintain any operating
that is required to comply with the limitations approved by the
emission limitation for formaldehyde Administrator.
and is not using an oxidation catalyst.
------------------------------------------------------------------------
As stated in Sec. 63.6120, you must comply with the following
requirements for performance tests and initial compliance
demonstrations:
[[Page 10545]]
Table 3 to Subpart YYYY of Part 63.--Requirements for Performance Tests
and Initial Compliance Demonstrations
------------------------------------------------------------------------
According to the
You must . . . Using . . . following
requirements . . .
------------------------------------------------------------------------
a. demonstrate formaldehyde Test Method 320 of formaldehyde
emissions meet the emission 40 CFR part 63, concentration must
limitations specified in appendix A; ASTM be corrected to 15
Table 1 by a performance D6348-03 provided percent O2, dry
test initially and on an that %R as basis. Results of
annual basis AND. determined in Annex this test consist
A5 of ASTM D6348-03 of the average of
is equal or greater the three 1 hour
than 70% and less runs. Test must be
than or equal to conducted within 10
130%; or other percent of 100
methods approved by percent load.
the Administrator.
-----------------------------
b. select the sampling port Method 1 or 1A of 40 if using an air
location and the number of CFR part 60, pollution control
traverse points AND. appendix A Sec. device, the
63.7(d)(1)(i). sampling site must
be located at the
outlet of the air
pollution control
device.
-----------------------------
c. determine the O2 Method 3A or 3B of measurements to
concentration at the 40 CFR part 60, determine O2
sampling port location AND. appendix A. concentration must
be made at the same
time as the
performance test.
-----------------------------
d. determine the moisture Method 4 of 40 CFR measurements to
content at the sampling part 60, appendix A determine moisture
port location for the or Test Method 320 content must be
purposes of correcting the of 40 CFR part 63, made at the same
formaldehyde concentration appendix A, or ASTM time as the
to a dry basis. D6348-03. performance test.
------------------------------------------------------------------------
As stated in Sec. Sec. 63.6110 and 63.6130, you must comply
with the following requirements to demonstrate initial compliance
with emission limitations:
Table 4 to Subpart YYYY of Part 63.--Initial Compliance With Emission
Limitations
------------------------------------------------------------------------
You have demonstrated initial
For the . . . compliance if . . .
------------------------------------------------------------------------
emission limitation for the average formaldehyde
formaldehyde.. concentration meets the emission
limitations specified in Table 1.
------------------------------------------------------------------------
As stated in Sec. Sec. 63.6135 and 63.6140, you must comply
with the following requirements to demonstrate continuing compliance
with operating limitations:
Table 5 of Subpart YYYY of Part 63.--Continuous Compliance With
Operating Limitations
------------------------------------------------------------------------
For each stationary combustion turbine
complying with the emission limitation You must demonstrate continuous
for formaldehyde . . . compliance by . . .
------------------------------------------------------------------------
1. with an oxidation catalyst......... continuously monitoring the
inlet temperature to the
catalyst and maintaining the 4-
hour rolling average of the
inlet temperature within the
range suggested by the
catalyst manufacturer.
----------------------------------------
2. without the use of an oxidation continuously monitoring the
catalyst. operating limitations that
have been approved in your
petition to the Administrator.
------------------------------------------------------------------------
As stated in Sec. 63.6150, you must comply with the following
requirements for reports:
Table 6 of Subpart YYYY of Part 63.--Requirements for Reports
------------------------------------------------------------------------
According to the
If you own or operate a . . you must . . . following
. requirements . . .
------------------------------------------------------------------------
1. stationary combustion report your semiannually,
turbine which must comply compliance status. according to the
with the formaldehyde requirements of
emission limitation. Sec. 63.6150.
-----------------------------
2. stationary combustion report (1) the fuel annually, according
turbine which fires flow rate of each to the requirements
landfill gas, digester gas fuel and the in Sec. 63.6150.
or gasified MSW equivalent heating values that
to 10 percent or more of were used in your
the gross heat input on an calculations, and
annual basis. you must
demonstrate that
the percentage of
heat input provided
by landfill gas,
digester gas, or
gasified MSW is
equivalent to 10
percent or more of
the gross heat
input on an annual
basis, (2) the
operating limits
provided in your
federally
enforceable permit,
and any deviations
from these limits,
and (3) any
problems or errors
suspected with the
meters.
-----------------------------
[[Page 10546]]
3. a lean premix gas-fired report (1) the annually, according
stationary combustion number of hours to the requirements
turbine or a diffusion distillate oil was in Sec. 63.6150.
flame gas-fired stationary fired by each new
combustion turbine as or existing
defined by this subpart, stationary
and you use any quantity of combustion turbine
distillate oil to fire any during the
new or existing stationary reporting period,
combustion turbine which is (2) the operating
located at the same major limits provided in
source. your federally
enforceable permit,
and any deviations
from these limits,
and (3) any
problems or errors
suspected with the
meters.
------------------------------------------------------------------------
You must comply with the applicable General Provisions
requirements:
Table 7 of Subpart YYYY of Part 63.--Applicability of General Provisions to Subpart YYYY
----------------------------------------------------------------------------------------------------------------
Citation Subject Applies to Subpart YYYY Explanation
----------------------------------------------------------------------------------------------------------------
Sec. 63.1........................ General applicability Yes........................ Additional terms
of the General defined in Sec.
Provisions. 63.6175.
Sec. 63.2........................ Definitions........... Yes........................ Additional terms
defined in Sec.
63.6175.
Sec. 63.3........................ Units and Yes........................
abbreviations.
Sec. 63.4........................ Prohibited activities. Yes........................
Sec. 63.5........................ Construction and Yes........................
reconstruction.
Sec. 63.6(a)..................... Applicability......... Yes........................
Sec. 63.6(b)(1)-(4).............. Compliance dates for Yes........................
new and reconstructed
sources.
Sec. 63.6(b)(5).................. Notification.......... Yes........................
Sec. 63.6(b)(6).................. [Reserved]............
Sec. 63.6(b)(7).................. Compliance dates for Yes........................
new and reconstructed
area sources that
become major.
Sec. 63.6(c)(1)-(2).............. Compliance dates for Yes........................
existing sources.
Sec. 63.6(c)(3)-(4).............. [Reserved]............
Sec. 63.6(c)(5).................. Compliance dates for Yes........................
existing area sources
that become major.
Sec. 63.6(d)..................... [Reserved]............
Sec. 63.6(e)(1).................. Operation and Yes........................
maintenance.
Sec. 63.6(e)(2).................. [Reserved]............
Sec. 63.6(e)(3).................. SSMP.................. Yes........................
Sec. 63.6(f)(1).................. Applicability of Yes........................
standards except
during startup,
shutdown, or
malfunction (SSM).
Sec. 63.6(f)(2).................. Methods for Yes........................
determining
compliance.
Sec. 63.6(f)(3).................. Finding of compliance. Yes........................
Sec. 63.6(g)(1)-(3).............. Use of alternative Yes........................
standard.
Sec. 63.6(h)..................... Opacity and visible No......................... Subpart YYYY does not
emission standards. contain opacity or
visible emission
standards.
Sec. 63.6(i)..................... Compliance extension Yes........................
procedures and
criteria.
Sec. 63.6(j)..................... Presidential Yes........................
compliance exemption.
Sec. 63.7(a)(1)-(2).............. Performance test dates Yes........................ Subpart YYYY contains
performance test
dates at Sec.
63.6110.
Sec. 63.7(a)(3).................. Section 114 authority. Yes........................
Sec. 63.7(b)(1).................. Notification of Yes........................
performance test.
Sec. 63.7(b)(2).................. Notification of Yes........................
rescheduling.
Sec. 63.7(c)..................... Quality assurance/test Yes........................
plan.
Sec. 63.7(d)..................... Testing facilities.... Yes........................
Sec. 63.7(e)(1).................. Conditions for Yes........................
conducting
performance tests.
Sec. 63.7(e)(2).................. Conduct of performance Yes........................ Subpart YYYY specifies
tests and reduction test methods at Sec.
of data. 63.6120.
Sec. 63.7(e)(3).................. Test run duration..... Yes........................
Sec. 63.7(e)(4).................. Administrator may Yes........................
require other testing
under section 114 of
the CAA.
Sec. 63.7(f)..................... Alternative test Yes........................
method provisions.
Sec. 63.7(g)..................... Performance test data Yes........................
analysis,
recordkeeping, and
reporting.
Sec. 63.7(h)..................... Waiver of tests....... Yes........................
Sec. 63.8(a)(1).................. Applicability of Yes........................ Subpart YYYY contains
monitoring specific requirements
requirements. for monitoring at
Sec. 63.6125.
Sec. 63.8(a)(2).................. Performance Yes........................
specifications.
Sec. 63.8(a)(3).................. [Reserved]............
Sec. 63.8(a)(4).................. Monitoring for control No.........................
devices.
[[Page 10547]]
Sec. 63.8(b)(1).................. Monitoring............ Yes........................
Sec. 63.8(b)(2)-(3).............. Multiple effluents and Yes........................
multiple monitoring
systems.
Sec. 63.8(c)(1).................. Monitoring system Yes........................
operation and
maintenance.
Sec. 63.8(c)(1)(i)............... Routine and Yes........................
predictable SSM.
Sec. 63.8(c)(1)(ii).............. Parts for repair of Yes........................
CMS readily available.
Sec. 63.8(c)(1)(iii)............. SSMP for CMS required. Yes........................
Sec. 63.8(c)(2)-(3).............. Monitoring system Yes........................
installation.
Sec. 63.8(c)(4).................. Continuous monitoring Yes........................ Except that subpart
system (CMS) YYYY does not require
requirements. continuous opacity
monitoring systems
(COMS).
Sec. 63.8(c)(5).................. COMS minimum No.........................
procedures.
Sec. 63.8(c)(6)-(8).............. CMS requirements...... Yes........................ Except that subpart
YYYY does not require
COMS.
Sec. 63.8(d)..................... CMS quality control... Yes........................
Sec. 63.8(e)..................... CMS performance Yes........................ Except for Sec.
evaluation. 63.8(e)(5)(ii), which
applies to COMS.
Sec. 63.8(f)(1)-(5).............. Alternative monitoring Yes........................
method.
Sec. 63.8(f)(6).................. Alternative to Yes........................
relative accuracy
test.
Sec. 63.8(g)..................... Data reduction........ Yes........................ Except that provisions
for COMS are not
applicable. Averaging
periods for
demonstrating
compliance are
specified at Sec.
Sec. 63.6135 and
63.6140.
Sec. 63.9(a)..................... Applicability and Yes........................
State delegation of
notification
requirements.
Sec. 63.9(b)(1)-(5).............. Initial notifications. Yes........................ Except that Sec.
63.9(b)(3) is
reserved.
Sec. 63.9(c)..................... Request for compliance Yes........................
extension.
Sec. 63.9(d)..................... Notification of Yes........................
special compliance
requirements for new
sources.
Sec. 63.9(e)..................... Notification of Yes........................
performance test.
Sec. 63.9(f)..................... Notification of No......................... Subpart YYYY does not
visible emissions/ contain opacity or VE
opacity test. standards.
Sec. 63.9(g)(1).................. Notification of Yes........................
performance
evaluation.
Sec. 63.9(g)(2).................. Notification of use of No......................... Subpart YYYY does not
COMS data. contain opacity or VE
standards.
Sec. 63.9(g)(3).................. Notification that Yes........................ If alternative is in
criterion for use.
alternative to
relative accuracy
test audit (RATA) is
exceeded.
Sec. 63.9(h)..................... Notification of Yes........................ Except that
compliance status. notifications for
sources not
conducting
performance tests are
due 30 days after
completion of
performance
evaluations. Sec.
63.9(h)(4) is
reserved.
Sec. 63.9(i)..................... Adjustment of Yes........................
submittal deadlines.
Sec. 63.9(j)..................... Change in previous Yes........................
information.
Sec. 63.10(a).................... Administrative Yes........................
provisions for
recordkeeping and
reporting.
Sec. 63.10(b)(1)................. Record retention...... Yes........................
Sec. 63.10(b)(2)(i)-(iii)........ Records related to SSM Yes........................
Sec. 63.10(b)(2)(iv)-(v)......... Records related to Yes........................
actions during SSM.
Sec. 63.10(b)(2)(vi)-(xi)........ CMS records........... Yes........................
Sec. 63.10(b)(2)(xii)............ Record when under Yes........................
waiver.
Sec. 63.10(b)(2)(xiii)........... Records when using Yes........................ For CO standard if
alternative to RATA. using RATA
alternative.
Sec. 63.10(b)(2)(xiv)............ Records of supporting Yes........................
documentation.
Sec. 63.10(b)(3)................. Records of Yes........................
applicability
determination.
Sec. 63.10(c).................... Additional records for Yes........................ Except that Sec.
sources using CMS. 63.10(c)(2)-(4) and
(9) are reserved.
Sec. 63.10(d)(1)................. General reporting Yes........................
requirements.
Sec. 63.10(d)(2)................. Report of performance Yes........................
test results.
Sec. 63.10(d)(3)................. Reporting opacity or No......................... Subpart YYYY does not
VE observations. contain opacity or VE
standards.
Sec. 63.10(d)(4)................. Progress reports...... Yes........................
Sec. 63.10(d)(5)................. Startup, shutdown, and No......................... Subpart YYYY does not
malfunction reports. require reporting of
startup, shutdowns,
or malfunctions.
Sec. 63.10(e)(1) and (2)(i)...... Additional CMS reports Yes........................
Sec. 63.10(e)(2)(ii)............. COMS-related report... No......................... Subpart YYYY does not
require COMS.
Sec. 63.10(e)(3)................. Excess emissions and Yes........................
parameter exceedances
reports.
[[Page 10548]]
Sec. 63.10(e)(4)................. Reporting COMS data... No......................... Subpart YYYY does not
require COMS.
Sec. 63.10(f).................... Waiver for Yes........................
recordkeeping and
reporting.
Sec. 63.11....................... Flares................ No.........................
Sec. 63.12....................... State authority and Yes........................
delegations.
Sec. 63.13....................... Addresses............. Yes........................
Sec. 63.14....................... Incorporation by Yes........................
reference.
Sec. 63.15....................... Availability of Yes........................
information.
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[FR Doc. 04-4530 Filed 3-4-04; 8:45 am]
BILLING CODE 6560-50-P