National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines

Note: EPA no longer updates this information, but it may be useful as a reference or resource.

[Federal Register: January 14, 2003 (Volume 68, Number 9)]
[Proposed Rules]
[Page 1887-1929]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr14ja03-11]

-----------------------------------------------------------------------

ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[OAR-2002-0060; FRL-7417-8]
RIN 2060-AG67

National Emission Standards for Hazardous Air Pollutants for
Stationary Combustion Turbines

AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.

-----------------------------------------------------------------------

SUMMARY: This action proposes 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 proposed NESHAP would 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. We estimate that 20
percent of the stationary combustion turbines affected by the proposed
rule will be located at major sources. As a result, the environmental,
energy, and economic impacts presented in this preamble reflect these
estimates. The proposed standards would protect public health by
reducing exposure to air pollution, by reducing total national HAP
emissions by an estimated 81 tons/year in the 5th year after the
standards are promulgated. This action also proposes to add Method 323
of 40 CFR part 63, appendix A for the measurement of formaldehyde
emissions from natural gas-fired stationary sources.

DATES: Comments. Submit comments on or before February 13, 2003.
Public Hearing. If anyone contacts us requesting to speak at a
public hearing by January 24, 2003, we will hold a public hearing on
January 29, 2003.

ADDRESSES: Comments may be submitted by mail (in duplicate, if
possible) to EPA West (Air Docket), U.S. EPA (MD-6102T), Room B-108,
1200 Pennsylvania Avenue, NW., Washington, DC 20460, Attention Docket
ID No. OAR-2002-0060. By hand delivery/courier, comments may be
submitted (in duplicate, if possible) to EPA Docket Center (Air
Docket), U.S. EPA, MD-6102T), Room B-108, 1301 Constitution Avenue,
NW., Washington, DC 20460, Attention Docket ID No. OAR-2002-0060.
Comments may be submitted electronically according to the detailed
instructions as provided in the SUPPLEMENTARY INFORMATION section.
Public Hearing. If a public hearing is held, it will be held at the
new EPA facility complex in Research Triangle Park, North Carolina.
Docket. Docket No. OAR-2002-0060 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: 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 roy.sims@epa.gov.

SUPPLEMENTARY INFORMATION: Regulated Entities. Categories and entities
potentially regulated by this action include:

----------------------------------------------------------------------------------------------------------------
Category SIC NAICS Examples of regulated entities
----------------------------------------------------------------------------------------------------------------
Any industry using a stationary combustion 4911 2211 Electric power generation,
turbine as defined in 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
proposed 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. 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 B108, 1301 Constitution Ave., NW., Washington, DC. 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.regulations.gov/ to submit or 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. Once in the system, select ``search,''
then key in the appropriate docket identification number.
Certain types of information will not be placed in the EPA Dockets.
Information claimed as CBI and other information whose disclosure is
restricted by statute, which is not included in the official public
docket, will not be available for public viewing in EPA's electronic
public docket. The EPA's policy is that copyrighted material will not
be placed in EPA's electronic public docket but will be available only
in printed paper form in the official public docket. To the extent
feasible, publicly available docket materials will be made available in
EPA's electronic public docket. When a document is selected from the
index list in EPA Dockets, the system will identify

[[Page 1889]]

whether the document is available for viewing in EPA's electronic
public docket. 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. The EPA
intends to work towards providing electronic access to all of the
publicly available docket materials through EPA's electronic public
docket.
For public commenters, it is important to note that EPA's policy is
that public comments, whether submitted electronically or on paper,
will be made available for public viewing in EPA's electronic public
docket as EPA receives them and without change, unless the comment
contains copyrighted material, CBI, or other information whose
disclosure is restricted by statute. When EPA identifies a comment
containing copyrighted material, EPA will provide a reference to that
material in the version of the comment that is placed in EPA's
electronic public docket. The entire printed comment, including the
copyrighted material, will be available in the public docket.
Public comments submitted on computer disks that are mailed or
delivered to the docket will be transferred to EPA's electronic public
docket. Public comments that are mailed or delivered to the Docket will
be scanned and placed in EPA's electronic public docket. Where
practical, physical objects will be photographed, and the photograph
will be placed in EPA's electronic public docket along with a brief
description written by the docket staff.
For additional information about EPA's electronic public docket
visit EPA Dockets online or see 67 FR 38102, May 31, 2002.
You may submit comments electronically, by mail, or through hand
delivery/courier. To ensure proper receipt by EPA, identify the
appropriate docket identification number in the subject line on the
first page of your comment. Please ensure that your comments are
submitted within the specified comment period. Comments received after
the close of the comment period will be marked ``late.'' The EPA is not
required to consider these late comments. However, late comments may be
considered if time permits. Electronically. If you submit an electronic
comment as prescribed below, EPA recommends that you include your name,
mailing address, and an e-mail address or other contact information in
the body of your comment. Also include this contact information on the
outside of any disk or CD ROM you submit, and in any cover letter
accompanying the disk or CD ROM. This ensures that you can be
identified as the submitter of the comment and allows EPA to contact
you in case EPA cannot read your comment due to technical difficulties
or needs further information on the substance of your comment. The
EPA's policy is that EPA will not edit your comment, and any
identifying or contact information provided in the body of a comment
will be included as part of the comment that is placed in the official
public docket and made available in EPA's electronic public docket. If
EPA cannot read your comment due to technical difficulties and cannot
contact you for clarification, EPA may not be able to consider your
comment.
Your use of EPA's electronic public docket to submit comments to
EPA electronically is EPA's preferred method for receiving comments. Go
directly to EPA Dockets at http://www.epa.gov/edocket, and follow the
online instructions for submitting comments. To access EPA's electronic
public docket from the EPA Internet Home Page, select ``Information
Sources,'' ``Dockets,'' and ``EPA Dockets.'' Once in the system, select
``search,'' and then key in Docket ID No. OAR-2002-0060. The system is
an ``anonymous access'' system, which means EPA will not know your
identity, e-mail address, or other contact information unless you
provide it in the body of your comment.
Comments may be sent by electronic mail (e-mail) to a-and-r-
docket@epa.gov, Attention Docket ID No. OAR-2002-0060. In contrast to
EPA's electronic public docket, EPA's e-mail system is not an
``anonymous access'' system. If you send an e-mail comment directly to
the Docket without going through EPA's electronic public docket, EPA's
e-mail system automatically captures your e-mail address. E-mail
addresses that are automatically captured by EPA's e-mail system are
included as part of the comment that is placed in the official public
docket and made available in EPA's electronic public docket.
You may submit comments on a disk or CD ROM that you mail to the
mailing address identified below. These electronic submissions will be
accepted in WordPerfect or ASCII file format. Avoid the use of special
characters and any form of encryption.
By Mail. Send your comments (in duplicate if possible) to: Air and
Radiation Docket and Information Center, U.S. EPA, Mailcode: 6102T,
1200 Pennsylvania Ave., NW, Washington, DC, 20460, Attention Docket ID
No. OAR-2002-0060. The EPA requests a separate copy also be sent to the
contact person listed above (see FOR FURTHER INFORMATION CONTACT).
By Hand Delivery or Courier. Deliver your comments to: EPA Docket
Center, Room B108, 1301 Constitution Ave., NW, Washington, DC, 20460,
Attention Docket ID No. OAR-2002-0060. Such deliveries are only
accepted during the Docket's normal hours of operation as identified
above.
Do not submit information that you consider to be CBI
electronically through EPA's electronic public docket or by e-mail.
Send or deliver information identified as CBI only to the following
address: Mr. Sims Roy, c/o OAQPS Document Control Officer (Room C404-
2), U.S. EPA, Research Triangle Park, 27711, Attention Docket ID No.
OAR-2002-0060. You may claim information that you submit to EPA as CBI
by marking any part or all of that information as CBI (if you submit
CBI on disk or CD ROM, mark the outside of the disk or CD ROM as CBI
and then identify electronically within the disk or CD ROM the specific
information that is CBI). Information so marked will not be disclosed
except in accordance with procedures set forth in 40 CFR part 2.
In addition to one complete version of the comment that includes
any information claimed as CBI, a copy of the comment that does not
contain the information claimed as CBI must be submitted for inclusion
in the public docket and EPA's electronic public docket. If you submit
the copy that does not contain CBI on disk or CD ROM, mark the outside
of the disk or CDROM clearly that it does not contain CBI. Information
not marked as CBI will be included in the public docket and EPA's
electronic public docket without prior notice. If you have any
questions about CBI or the procedures for claiming CBI, please consult
the person identified in the FOR FURTHER INFORMATION CONTACT section.
You may find the following suggestions helpful for preparing your
comments:
1. Explain your views as clearly as possible.
2. Describe any assumptions that you used.
3. Provide any technical information and/or data you used that
support your views.
4. If you estimate potential burden or costs, explain how you
arrived at your estimate.
5. Provide specific examples to illustrate your concerns.
6. Offer alternatives.
7. Make sure to submit your comments by the comment period deadline
identified.

[[Page 1890]]

8. To ensure proper receipt by EPA, identify the appropriate docket
identification number in the subject line on the first page of your
response. It would also be helpful if you provided the name, date, and
Federal Register citation related to your comments.
Public Hearing. Persons interested in presenting oral testimony or
inquiring as to whether a hearing is to be held should contact Mrs.
Kelly Hayes, Combustion Group, Emission Standards Division (MD-C439-
01), U.S. EPA, Research Triangle Park, North Carolina 27711, (919) 541-
5578 at least 2 days in advance of the public hearing. Persons
interested in attending the public hearing must also call Mrs. Hayes to
verify the time, date, and location of the hearing. The public hearing
will provide interested parties the opportunity to present data, views,
or arguments concerning the proposed rule. If a public hearing is
requested and held, EPA will ask clarifying questions during the oral
presentation but will not respond to the presentations or comments.
Written statements and supporting information will be considered with
equivalent weight as any oral statement and supporting information
presented at a public hearing, if held.
Outline. The information presented in this preamble is organized as
follows:

I. Background
A. What is the regulatory development background of the source
category?
B. What is the source of authority for development of NESHAP?
C. What criteria are used in the development of NESHAP?
D. What are the health effects associated with HAP from
stationary combustion turbines?
II. Summary of the Proposed Rule
A. Am I subject to the proposed rule?
B. What source categories and subcategories are affected by the
proposed 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 monitoring and testing methods are available to measure
these low concentrations of CO and formaldehyde?
H. What are the notification, recordkeeping and reporting
requirements?
III. Rationale for Selecting the Proposed Standards
A. How did we select the source category and any subcategories?
B. What about stationary combustion turbines located at area
sources?
C. What is the affected source?
D. How did we determine the basis and level of the proposed
emission limitations for existing sources?
E. How did we determine the basis and level of the proposed
emission limitations and operating limitations for new sources?
F. How did we select the format of the standard for new
diffusion flame combustion turbines?
G. How did we select the initial compliance requirements?
H. How did we select the continuous compliance requirements?
I. How did we select the monitoring and testing methods to
measure these low concentrations of CO and formaldehyde?
J. How did we select the notification, recordkeeping and
reporting requirements?
IV. 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 nonair health, environmental and energy impacts?
V. Solicitation of Comments and Public Participation
A. General
B. Can we achieve the goals of the proposed rule in a less
costly manner?
C. Limited Use Subcategory
VI. Administrative Requirements
A. Executive Order 12866, Regulatory Planning and Review
B. Executive Order 13132, Federalism
C. Executive Order 13175, Consultation and Coordination with
Indian Tribal Governments
D. Executive Order 13045, Protection of Children from
Environmental Health Risks and Safety Risks
E. Executive Order 13211, Actions Concerning Regulations that
Significantly Affect Energy Supply, Distribution, or Use
F. Unfunded Mandates Reform Act of 1995
G. Regulatory Flexibility Act (RFA), as Amended by the Small
Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5
U.S.C. 601 et seq.
H. Paperwork Reduction Act
I. National Technology Transfer and Advancement Act

I. Background

A. 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 proposed rule for stationary
combustion turbines.

B. 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 ton/yr of any one HAP or 25 ton/yr of any combination
of HAP.

C. 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
5 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

[[Page 1891]]

reductions, any nonair quality health and environmental impacts, and
energy requirements.

D. What Are the Health Effects Associated With HAP From Stationary
Combustion Turbines?

Emission data collected during development of the proposed 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.
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 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. Acetaldehyde is a potential
carcinogen in humans.

II. Summary of the Proposed Rule

A. Am I Subject to the Proposed Rule?

The proposed 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 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.
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
incorporated the requirements of section 112(n)(4) of the CAA into our
NESHAP for Oil and Natural Gas Production Facilities in subpart HH of
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.
Six subcategories have been defined within the stationary
combustion turbine source category. While all stationary combustion
turbines are subject to the proposed rule, each subcategory has
distinct requirements. For example, existing diffusion flame combustion
turbines and stationary combustion turbines with a rated peak power
output of less than 1.0 megawatt (MW) (at International Organization
for Standardization (ISO) standard day conditions) are not required to
comply with emission limitations, recordkeeping or reporting
requirements in the proposed rule. New or reconstructed stationary
combustion turbines and existing lean premix stationary combustion
turbines with a rated peak power output of 1.0 MW or more that either
operate exclusively as an emergency stationary combustion turbine, as a
limited use stationary combustion turbine, or as a stationary
combustion turbine which burns landfill gas or digester gas as its
primary fuel must only comply with the initial notification
requirements. New or reconstructed diffusion flame or lean premix
combustion turbines must comply with emission limitations,
recordkeeping and reporting requirements in the proposed rule. The
emission limitations for each subcategory are summarized in Table 2 of
this preamble. You must determine your source's subcategory to
determine which requirements apply to your source.
The proposed rule does not apply to stationary combustion turbines
located at an area source of HAP emissions. An area source of HAP
emissions is a plant site that does not emit any single HAP at a rate
of 10 tons (9.07 megagrams) or greater per year or any combination of
HAP at a rate of 25 tons (22.68 megagrams) or greater per year. To
determine whether a facility is a major source, EPA will accept HAP
emissions estimated using HAP emission factors listed in Table 1 of
this preamble.

[[Page 1892]]

Table 1.--Summary of HAP Emission Factors
----------------------------------------------------------------------------------------------------------------
HAP emission
Turbine Load Fuel factor (lb/
MMBtu)
----------------------------------------------------------------------------------------------------------------
Diffusion Flame......................... All loads................. Natural Gas............... 0.0188
Diffusion Flame......................... £80%............ Natural Gas............... 0.00479
Diffusion Flame......................... All loads................. Diesel.................... 0.00241
Diffusion Flame......................... £80%............ Diesel.................... 0.00233
Lean Premix............................. All loads................. Natural Gas............... 0.000644
Lean Premix............................. £80%............ Natural Gas............... 0.000212
----------------------------------------------------------------------------------------------------------------

If the turbine mainly operates at high load, the emission factor
for greater than 80 percent load should be used. If the turbine
operates on varying loads, the emission factor for all loads should be
used. Emission factors were developed based on data from the combustion
turbines emissions database. A copy of the emissions database may be
downloaded off the internet at http://www.epa.gov/ttn/atw/combust/turbine/turbpg.html.
The proposed 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
proposed rule.
Finally, the proposed rule does not apply to stationary combustion
engine test cells/stands since these facilities will be covered by
another NESHAP, 40 CFR part 63, subpart PPPPP.

B. What Source Categories and Subcategories Are Affected by the
Proposed Rule?

The proposed rule covers stationary combustion turbines. A
stationary combustion turbine is 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. The combustion turbine may,
however, be mounted on a vehicle for portability or transportability.
Stationary combustion turbines have been divided into the following
six subcategories: (1) Emergency stationary combustion turbines, (2)
limited use stationary combustion turbines, (3) stationary combustion
turbines which fire landfill gas or digester gas as their primary fuel,
(4) stationary combustion turbines of less than 1 MW rated peak power
output, (5) stationary diffusion flame combustion turbines, and (6)
stationary lean premix combustion turbines.
An emergency stationary combustion turbine means any stationary
combustion turbine that operates as a mechanical or electrical power
source when the primary power source for a facility has been rendered
inoperable by an emergency situation. One example is emergency power
for critical networks or equipment when electric power from the normal
source of power is interrupted. Another example is to pump water in the
case of fire or flood. Peaking units at electric utilities and other
types of stationary combustion turbines that typically operate at low
capacity factors, but are not confined to operation in an emergency,
are not emergency stationary combustion turbines.
A limited use stationary combustion turbine means any stationary
combustion turbine that operates 50 hours or less per calendar year.
One example is a stationary combustion turbine used to stabilize
electrical power voltage and protect sensitive electronic equipment
during periods of brown outs. Another example is periodic operation of
an emergency stationary combustion turbine to check readiness or
perform maintenance checks. Since electrical power has not been
interrupted during these readiness and maintenance checks, the
stationary combustion turbine is not operating as an emergency
stationary combustion turbine.
We are specifically soliciting comments on creating a subcategory
of limited use combustion turbines with a capacity utilization of 10
percent or less. This is further discussed in the ``Solicitation of
Comments and Public Participation'' section of this preamble.
Stationary combustion turbines which fire landfill gas or digester
gas as their primary fuel 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. Given the very small size of
these stationary combustion turbines and the lack of application of HAP
emission control technologies, we have concerns about the applicability
of HAP emission control technology to them.
The stationary diffusion flame combustion turbines subcategory
includes only diffusion flame combustion turbines that are greater than
1 MW rated peak power output and are not emergency stationary
combustion turbines, limited use stationary combustion turbines, or
stationary combustion turbines which fire landfill gas or digester gas
as their primary fuel. 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 pollutants emissions from these turbines can be
significantly decreased with the addition of air pollution control
equipment.
The stationary lean premix combustion turbines subcategory includes
only lean premix combustion turbines that are greater than 1 MW rated
peak power output and are not emergency stationary combustion turbines,
limited use stationary combustion turbines, or stationary combustion
turbines which fire landfill gas or digester gas as their primary fuel.
Lean premix technology, introduced in the 1990's, was developed to
reduce NO_X emissions without the use of add on controls. In
a staged lean premix combustor, the air and fuel are thoroughly mixed
to form a lean mixture before delivery to the combustor. The staged
entry limits the flame temperature and the residence time at the peak
flame temperature. Lean premix combustors emit lower levels of
NO_X, carbon monoxide (CO), formaldehyde and other HAP than
diffusion flame combustion turbines.

[[Page 1893]]

C. What Are the Primary Sources of HAP Emissions and What Are the
Emissions?

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 an existing lean premix stationary
combustion turbine or a new or reconstructed stationary combustion
turbine located at a major source of HAP emissions, you must comply
with one of the following two emission limitations by the effective
date of the standard (or upon startup if you start up your stationary
combustion turbine after the effective date of the standard): (1)
Reduce CO emissions in the exhaust from the new or reconstructed
stationary combustion turbine by 95 percent or more, if you use an
oxidation catalyst emission control device; or (2) reduce the
concentration of formaldehyde in the exhaust from the new or
reconstructed stationary combustion turbine to 43 parts per billion by
volume or less, dry basis (ppbvd), at 15 percent oxygen, if you use
means other than an oxidation catalyst emission control device.
There are no operating limitations if you choose to comply with the
emission limitation for CO emission reduction. If you comply with the
emission limitation for formaldehyde emissions and your stationary
combustion turbine is not lean premix or diffusion flame, you must
comply with any additional operating limitations approved by the
Administrator, as discussed later.
Finally, as mentioned earlier, stationary combustion turbines with
a rated peak power output of less than 1.0 MW, emergency stationary
combustion turbines, limited use stationary combustion turbines, and
stationary combustion turbines which burn landfill gas or digester gas
as their primary fuel, are not required to comply with these emission
limitations. In addition, existing diffusion flame stationary
combustion turbines, are not required to comply with these emission
limitations. The emission limitations for each subcategory are
summarized in Table 2 of this preamble.

Table 2.--Summary of Emission Limitations
----------------------------------------------------------------------------------------------------------------
Subcategory Emission limitation Comment
----------------------------------------------------------------------------------------------------------------
Existing Diffusion Flame Stationary None...................... No requirements.
Combustion Turbine £= 1.0 MW.
Existing Lean Premix Stationary (1) Reduce CO emissions by
Combustion Turbine £= 1.0 95% or more, if you use
MW. an oxidation catalyst
emission control device.
or.......................
(2) Reduce the
concentration of
formaldehyde to 43 ppbvd
@ 15% O₂, if you use
means other than an
oxidation catalyst
emission control device.
or
New/Reconstructed Stationary Combustion
Turbine £= 1.0 MW.
Emergency Stationary Combustion Turbine No emission limitations... Initial notification requirements only.
or....................................
Limited Use Stationary Combustion
Turbine
or....................................
Landfill/Digester Gas Stationary
Combustion Turbine.
<= 1 MW Stationary Combustion Turbine.. None...................... No requirements.
----------------------------------------------------------------------------------------------------------------

E. What Are the Initial Compliance Requirements?

The initial compliance requirements for a stationary combustion
turbine vary depending on the subcategory of your combustion turbine
and your control strategy.
If you operate a new or reconstructed stationary combustion turbine
and comply with the emission limitation for CO emission reduction, you
must install a continuous emission monitoring system (CEMS) to measure
CO and either carbon dioxide or oxygen simultaneously at the inlet and
outlet of the oxidation catalyst emission control device. To
demonstrate initial compliance, you must conduct an initial performance
evaluation using Performance Specifications 3 and 4A of 40 CFR part 60,
appendix B. You must demonstrate that the reduction of CO emissions is
at least 95 percent using the first 4-hour average after a successful
performance evaluation. Your inlet and outlet measurements must be on a
dry basis and corrected to 15 percent oxygen or equivalent carbon
dioxide content. You must also conduct an annual relative accuracy test
audit (RATA) of the CEMS using Performance Specifications 3 and 4A of
40 CFR part 60, appendix B.
If you operate a new or reconstructed combustion turbine or an
existing lean premix combustion turbine and comply with the emission
limitation for formaldehyde emissions, you must conduct an initial
performance test using Test Method 320 of 40 CFR part 63, appendix A;
ARB Method 430 of California Environmental Protection Agency, Air
Resources Board, 2020 L Street, Sacramento, CA 95812; or EPA Solid
Waste (SW)-846 Method 0011 to demonstrate that the outlet concentration
of formaldehyde is 43 ppbvd or less (corrected to 15 percent oxygen).
Natural gas-fired sources may also use the proposed Test Method 323 of
40 CFR part 63, appendix A, to measure formaldehyde. 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 Method 4 of 40 CFR
part 60, appendix A.
As stated previously, if you choose to comply with the emission
limitation for formaldehyde emissions and your stationary combustion
turbine is not lean premix or diffusion flame, you must also 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

[[Page 1894]]

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 or
unreasonable 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 all
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 CO emission reduction
limitation, you must calibrate and operate your CEMS according to the
requirements in 40 CFR 63.8. You must continuously monitor and record
the CO concentration before and after the oxidation catalyst emission
control device and calculate the percent reduction of CO emissions
hourly. The reduction in CO emissions must be 95 percent or more, based
on a rolling 4-hour average, averaged every hour.
To demonstrate continuous compliance with the operating limitations
(if applicable), you must continuously monitor the values of any
parameters which have been approved by the Administrator as operating
limitations.
The proposed rule does not require your lean premix combustion
turbine to demonstrate continuous compliance. It is assumed that if you
meet the low NO_X emission levels required by your federally
enforceable permit (or guaranteed by the turbine manufacturer if there
is no permit level), your turbine is in compliance with the 43 ppbvd
formaldehyde emission limit.

G. What Monitoring and Testing Methods Are Available to Measure These
Low Concentrations of CO and Formaldehyde?

Continuous emissions monitoring systems are available which can
accurately measure CO emission reduction at the low concentrations
found in the combustion turbine exhaust following an oxidation catalyst
emission control device. Our performance specification for CO CEMS (PS-
4A) of 40 CFR part 60, appendix A, however, has not been updated
recently and does not reflect the performance capabilities of these
systems. We are currently undertaking a review of PS-4A of 40 CFR part
60, appendix A, for CO CEMS and, in conjunction with this effort, we
solicit comments on the performance capabilities of CO CEMS and their
ability to accurately measure the low concentrations of CO experienced
in the exhaust of a combustion turbine following an oxidation catalyst
emission control device.
Similarly, our Fourier Transform Infrared (FTIR) test method,
Method 320 of 40 CFR part 63, appendix A, as well as EPA SW-846 Method
0011 and CARB Method 430, can be used to accurately measure
formaldehyde concentrations in the exhaust of a combustion turbine as
low as 43 ppbvd. As these test methods are currently written, however,
they do not provide for this level of accuracy. These methods must be
used with some revisions to achieve such accuracy.
As a result, we are currently undertaking a review of our FTIR
method, Method 320 of 40 CFR part 63, appendix A, to incorporate
revisions to ensure it can be used to accurately measure formaldehyde
concentrations as low as 43 ppbvd in the exhaust from a combustion
turbine. In conjunction with this effort, we solicit comments on
revisions to Method 320 of 40 CFR part 63, appendix A, to ensure
accurate measurement of such low concentrations of formaldehyde.
We are also proposing to add Method 323 of 40 CFR part 63, appendix
A. Method 323 is for the measurement of formaldehyde emissions from
natural gas-fired stationary sources using acetyl acetone
derivitization. We solicit comments on the use of this method to
measure low concentrations of formaldehyde.

H. 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 source is located at a major source, has greater than 1
MW rated peak power output, and is an emergency stationary combustion
turbine, limited use stationary combustion turbine or a combustion
turbine which fires landfill or digester gas as its primary fuel, you
must submit only an initial notification.
For each combustion turbine subject to the emission limitations,
you must

[[Page 1895]]

record all of the data necessary to determine if you are in compliance
with the emission limitations. 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.
You must submit a compliance report semiannually for each new or
reconstructed stationary combustion turbine that must comply with the
CO emission reduction limitation. This report must contain the company
name and address, a statement by a responsible official that the report
is accurate, a statement of compliance, or documentation of any
deviation from the requirements of the proposed rule during the
reporting period.

III. Rationale for Selecting the Proposed 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. Section 112 of
the CAA 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 six subcategories of stationary combustion turbines
located at major sources: (1) Emergency stationary combustion turbines,
(2) limited use stationary combustion turbines, (3) stationary
combustion turbines which fire landfill gas or digester gas as their
primary fuel, (4) stationary combustion turbines of less than 1 MW
rated peak power output, (5) stationary diffusion flame combustion
turbines, and (6) stationary lean premix combustion turbines.
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. An analysis of the
formaldehyde emissions data shows that uncontrolled formaldehyde
emissions from stationary lean premix combustion turbines are
comparable to controlled formaldehyde emissions from stationary
diffusion flame combustion turbines controlled with oxidation catalyst
systems. Due to the difference in the two technologies, we decided to
establish subcategories for diffusion flame and lean premix stationary
combustion turbines.
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.
Limited use stationary combustion turbines were also identified as
a subcategory. These types of stationary combustion turbines are
operated 50 hours per calendar year or less. They are used primarily to
stabilize electrical power voltage levels during periods of brown outs
to prevent damage to sensitive electronic equipment. As with emergency
stationary combustion turbines, they are operated 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.
Similarly, stationary combustion turbines which fire landfill gas
or digester gas as their primary fuel were identified as a subcategory.
Landfill and digester gases 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 and, to our knowledge,
none use emission control technology to reduce HAP. Given the very
small size of these stationary combustion turbines and the lack of
application of HAP emission control technologies, we have concerns
about the applicability of HAP emission control technology to them.

B. What About Stationary Combustion Turbines Located at Area Sources?

The proposed rule does not apply to stationary combustion turbines
located at an area 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 proposed rule does not
apply to these stationary combustion turbines.

C. What Is the Affected Source?

The proposed rule applies to any stationary combustion turbine
located at a major source. Consequently, stationary combustion turbines
located at major sources of HAP emissions are the affected source under
the proposed rule.

D. How Did We Determine the Basis and Level of the Proposed 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.
1. MACT Floor for Existing Diffusion Flame Combustion Turbines
To determine the MACT floor for existing stationary diffusion flame
combustion turbines, we primarily consulted two databases: an inventory
database and an emissions database. The MACT floors and MACT for
stationary diffusion flame combustion turbines located at major sources
were developed through the analyses of these databases.
The inventory database provides population information on
stationary combustion turbines in the United States (U.S.) and was
constructed in order to support the proposed rulemaking. 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 90 percent of those turbines
are assumed to be diffusion flame combustion turbines, based on

[[Page 1896]]

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 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. However, less than 3 percent of existing
stationary diffusion flame combustion 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;
thus, the average of the best performing 12 percent of existing
diffusion flame combustion turbines is no HAP emissions reductions.
We also investigated the use of good operating practices for
stationary diffusion flame combustion turbines to determine if the use
of such practices might identify a MACT floor. There are no references
in the inventory database to good operating practices for any
stationary combustion turbines.
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 good operating
practices which could reduce HAP emissions or which could serve to
identify a MACT floor.
We also investigated switching fuels in existing diffusion flame
combustion turbines using fuels which result in higher HAP emissions
with fuels that result in lower HAP emissions. When we compared the HAP
emissions of the various fuels from combustion turbines using the April
2000 revision of Chapter 3.1 (Stationary Gas Turbines) of ``Compilation
of Air Pollutant Emission Factors AP-42, Fifth Edition, Volume 1:
Stationary Point and Area Sources,'' we could not find a fuel that was
clearly less HAP emitting. The summation of emission factors for
various HAP when using natural gas (usually considered the cleanest
fuel), diesel fuel, landfill, or digester gas were comparable based on
the emission factor information that is available. Therefore, we could
not identify a MACT floor based on use of a particular fuel.
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 to identify a MACT floor.
As a result, we concluded the MACT floor for existing stationary
diffusion flame combustion turbines is no emissions reductions.
2. MACT for Existing Diffusion Flame Combustion Turbines
To determine MACT for existing stationary diffusion flame
combustion turbines, we evaluated regulatory alternatives more
stringent than the MACT floor. For existing diffusion flame sources, in
terms of an emission control technology which could serve as the basis
for MACT, we considered two beyond-the-floor options. The first option
considered was the use of an oxidation catalyst emission control
device. However, we concluded that the incremental cost per ton of HAP
removed for this option is excessive.
The incremental cost per ton is the difference in annual costs
between this regulatory option and the MACT floor divided by the
difference in annual emissions. It is often used as a measure of the
economic feasibility of applying emission control technology to a
source.
We also considered the nonair 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 nonair health or environmental impacts. However, as
stated above, we did not adopt this regulatory option due to cost
considerations.
The second option considered was to switch fuels in existing
turbines using fuels which result in higher HAP emissions with fuels
that result in lower HAP emissions. As stated above, we could not find
a fuel that was clearly less HAP emitting. Therefore, we could find no
basis to further consider fuel switching as a beyond-the-floor HAP
emissions reductions option. We were unable to identify any other
beyond-the-floor regulatory option to consider. As discussed above, we
are not aware of any specific good operating practices for diffusion
flame turbines that could reduce HAP emissions. As a result, we
concluded that MACT for existing diffusion flame combustion turbines is
the MACT floor (i.e., no emissions reductions).
3. MACT Floor for Existing Lean Premix Combustion Turbines
There are an estimated 800 lean premix combustion turbines in the
U.S., of which 160 are estimated to be major sources. For existing lean
premix combustion turbines, we must establish a MACT floor which
represents the average emission limitation achieved by the best
performing 12 percent of the existing sources for which we have
emissions information. We have emissions information on five existing
lean premix combustion turbines. Therefore, we plan to establish the
MACT floor based on the performance of the best performing lean premix
combustion turbine. (This best performing turbine represents the top 20
percent of the existing turbines for which we have emissions
information and will also be used to establish the MACT floor for new
lean premix combustion turbines.) The best performing existing lean
premix combustion turbine achieved a level of formaldehyde
concentration emission which averaged 6.1 parts per billion (ppb)
formaldehyde at 15 percent oxygen (O2). This is the best performer out
of five lean premix combustion turbine tests for which we have data.
The three-run average formaldehyde emissions from these five turbines
ranged from 6.1 to 41 ppb formaldehyde. The formaldehyde concentrations
for the individual runs for the best performing turbine were 5.1 ppb,
5.7 ppb, and 7.7 ppb.
The test method that was used to measure the emissions from the
best performing turbine was California Air Resources Board (CARB)
Method 430. We do not believe that the MACT emission limit should be
set lower than the limit of detection of the method. If it were, we
could not determine whether a source with test results at the limit of
detection was actually in compliance with the MACT emission limit. For
the test runs on the best

[[Page 1897]]

performing turbine, we determined that the method had a minimum
detection level (MDL) of between 2 and 3 ppb formaldehyde. We expect
the MDL to vary somewhat in actual practice and, thus, do not assume
that the MDL would be the same if the method were run by another person
or at another laboratory. We have no information regarding the
distribution of the CARB Method 430 MDL actually achieved by other
testers. We want to ensure that the MACT floor reflects the variability
in the limit of detection determined by different, competent testers
throughout the U.S. using the same method, i.e., CARB Method 430. We
only have one test, the test conducted on the best performing turbine,
to try to determine a limit of detection for this method, and this is
not enough information to determine the variability in the limit of
detection among different testers. If we had sufficient information on
the limit of detection determined by different competent testers using
Method 430, under similar conditions, we would analyze the results to
determine the average limit of detection and its standard deviation. To
establish a limit of detection that would be achievable by
approximately 99 percent of all the testers, we would add three times
the standard deviation to the average limit of detection. Since we do
not have this information, we can attempt to estimate it. We believe
that it is reasonable to assume that the standard deviation of the
limit of detection is no greater than the single estimate of the limit
that we have. If we multiply the single value of the limit of detection
by three and add it to itself, the result is an estimate of the upper
bound for the limit of detection that is four times the single measured
value that we have. Based on the considerations above, the lowest MACT
floor that we believe would take into account the variability in the
MDL is 12 ppb. This level provides a safety factor of four to account
for uncertainty in whether testers could routinely achieve a limit of
detection of 2 to 3 ppb formaldehyde.
The combustion turbine MACT would be a national standard, and
therefore, the MACT limit should reflect variations in the performance
of the best performing turbine that could occur. There are two major
sources of variability that together produce the total variability
observed in the emissions sample results. These sources of variability
are: the actual variability in the emissions, and the variability
associated with procedures for sampling and analyzing the emissions
samples. We believe there is substantial basis to conclude that sources
of variability unrelated to turbine performance account for the
differences in formaldehyde emissions concentrations between the five
turbines. We discuss these sources of variability in more detail below.
When we began investigating the possible sources of the actual
(non-sampling, non-analytical) variability in lean premix combustion
turbine emissions, we realized that turbine performance was only one of
several possible sources of that variability, and that turbine
emissions also could vary widely due to environmental and operational
factors that are unrelated to turbine performance and that are beyond
an operator's control.
Specifically, formaldehyde concentrations are expected to vary
temporally (e.g., seasonally) and spatially (e.g., geographically) due
to environmental and operational factors such as temperature, humidity,
atmospheric pressure, fuel quality, and the concentrations of
formaldehyde present in the ambient air. It is our judgement that if
the turbines were tested at various times during the year and at
various locations throughout the U.S., the concentration of
formaldehyde emitted by a given turbine could vary by a factor of seven
or more, solely due to geographic and temporal differences in
temperature, humidity, atmospheric pressure, fuel quality, and
formaldehyde concentration in the ambient air. This factor is based not
only on the short term variability of the data for the turbine with the
lowest reported formaldehyde emissions, but also on the test data from
all five turbines.
Variations in temperature, humidity, atmospheric pressure, and fuel
quality are known to have resulted in fluctuations in criteria
pollutant stack concentrations (e.g., NO_X, VOC, and CO), and
we anticipate that they also would cause variations in formaldehyde
concentrations in the combustion turbine stack. An owner or operator
cannot control the variability of environmental parameters such as
ambient temperature, humidity, or atmospheric pressure. With regard to
fuel quality, an owner or operator cannot control the quality of the
natural gas delivered through a pipeline, or the nature and
concentration of natural gas additives or contaminants. The five
turbines for which we have formaldehyde emissions data operate at four
locations in the Western U.S. that are at considerably different
altitudes. Moreover, each of the five turbines was sampled over only a
3-hour period, and the five sampling events occurred in four different
months of the year: April, May, June (two turbines), and December.
Therefore, we believe that the variability in formaldehyde
concentration of the turbine emissions will be greater than the
variability reflected in the 3-hour sampling period.
Furthermore, we believe that the variability observed in the
available turbine emissions data may reflect the variability of
formaldehyde concentrations in ambient air--much of which is due to
natural causes. The average concentration of formaldehyde in ambient
air varies between 2 and 25 ppb within the U.S., with a U.S. annual
average urban concentration of 5.17 ug/m\3\ (4.2 ppb).\1\ The
difference between hourly maximum and minimum formaldehyde
concentrations across the U.S. would be even greater than the average
annual 23 ppb range in U.S. formaldehyde concentrations. We do not have
information that specifically shows that the ambient concentration of
formaldehyde affects the stack outlet concentration of formaldehyde. We
expect that some formaldehyde, especially the portion that goes through
the combustors, would be destroyed. However, about two-thirds of the
inlet combustion turbine air bypasses the combustors. We are not sure
that all of the ambient formaldehyde that enters with the combustion
air is destroyed and, therefore, ambient formaldehyde may affect the
formaldehyde concentration in the outlet stack of the combustion
turbine. For example, if half of the ambient formaldehyde passes
through to the outlet stack, the annual average contribution of ambient
formaldehyde to the stack formaldehyde concentration may be in the 10
ppb range in some parts of the U.S. This means that hourly formaldehyde
emissions from the outlet stack of a given turbine could differ by over
10 ppb based solely on the region of the country where the turbine is
located.
---------------------------------------------------------------------------

\1\ 1998 National Air Quality and Emission Trends Report, Table
5-2 and Figure 5-1a.
---------------------------------------------------------------------------

Sampling variability is a result of the fact that it is impossible
to collect two samples in exactly the same way. Sampling variability
occurs both when an individual intends to collect replicate samples of
the same emissions stream, and when sampling is conducted by different
personnel using different procedures and different equipment under
different physical conditions. If the same sampling personnel collect a
suite of samples using the same equipment and procedures, the
variability of the sampling results will be reduced. However, a given
individual or a given piece of equipment may impart bias, a

[[Page 1898]]

systematic error, into the sampling procedure. In the context of an
aggregate of data collected by different personnel using different
procedures and different equipment under different physical conditions,
this bias could have the effect of increasing the variability of the
data. The emissions sample results for the five turbines evaluated for
the proposed rule were provided by state agencies, and samples were not
collected by the same sampling personnel, or even personnel acting in
coordination with one another and following the same sampling plan and
methodologies, increasing the non-systematic sampling-induced
variability across the five sets of turbine samples and also increasing
the chance that any bias imposed on each set of turbine samples might
also increase the variability of the results. Moreover, two different
sampling and analysis procedures were used to collect the samples, EPA
Method 0011 and CARB Method 430, likely introducing additional
variability into the sampling procedure. For example, EPA generally
recognizes that the quality assurance/quality control (QA/QC) protocols
for CARB Method 430 are more rigorous than those for EPA Method 0011.
Similar to sampling variability, variability occurs when samples are
analyzed at the same time in the same laboratory (e.g., variability is
seen in the results of a laboratory's repeated analysis of the same
sample) and occurs when samples are analyzed by different laboratories.
For example, analytic variability may result from the use of different
analytical procedures, different equipment, different laboratory
environments, different reagents, different sampling handling
procedures, and different analysts. The emissions samples evaluated for
the proposed rule were analyzed in different laboratories, by different
analysts, and using two different analytical procedures. The EPA
suspects that sampling and analytic variability may be a significant
source of the variability of formaldehyde emissions results reported
for the five tested turbines, and that if stricter QA/QC protocols were
followed, the results for the five turbines might have been closer in
magnitude.
One measure of overall variability (i.e., variability from all
sources--environmental, operational, test method, etc.) is the
variability of formaldehyde concentration that the best performing
turbine demonstrated during the three test runs. The formaldehyde
concentration varied between 5.1 and 7.7 ppb formaldehyde, a factor of
1.5 during only a 3-hour period. Another measure of formaldehyde
concentration variability is the variability in formaldehyde
concentration from the five lean premix combustion turbines tested. As
stated previously, the average formaldehyde concentration varied
between 6.1 and 41 ppb (a factor of seven). We reviewed the emission
test reports and could not find any specific reason to account for the
variability. These tests were properly conducted, and the lean premix
combustion turbines were operating properly. Therefore, we believe that
at least some portion, and possibly all, of that variability is due to
factors other than turbine performance. As a result, we believe that
some variability in formaldehyde concentration of the best performing
turbine will occur beyond the variability reflected by the three test
runs. It is our judgement that if the best performing turbine were
tested at various times during the year and at various locations
throughout the U.S., the overall formaldehyde concentration of the best
performing turbine could vary by a factor of seven or more. This factor
is based on the short term variability of the test data from the best
performing turbine and also on the test data from the five turbine
tests mentioned previously. Therefore, we believe that 43 ppbvd
formaldehyde is a reasonable approximation of the performance of the
best performing turbine, taking into account all of the types of
variability discussed above. As a result, we are proposing an emission
limit of 43 ppbvd formaldehyde as the MACT floor for existing lean
premix combustion turbines.
The lean premix combustor turbine technology varies to some extent
regarding its uncontrolled emissions of NO_X and CO and
possibly HAP. The data that we have obtained for the five source tests
were based primarily on lean premix combustor turbines that can achieve
lower than 15 ppm NO_X and less than 5 ppm CO (at full load)
at 15 percent O₂ without add-on controls. Lean premix
combustor turbines which have these characteristics are the types of
lean premix combustor turbines that we believe will most likely achieve
the 43 ppb formaldehyde emission limit. Other types of lean premix
combustor turbines which achieve 45 ppm NO_X and as high as
200 ppm CO at 15 percent O₂ may not achieve the 43 ppb
formaldehyde emission limit. Typically, the lean premix combustor
turbines in the latter category are smaller aeroderivative turbines.
Therefore, we realize that not all lean premix combustor turbines
will be able to achieve the 43 ppb formaldehyde emission limitation and
some will have to install add-on controls. Most new turbines projected
to be installed at power plants are expected to be able to achieve the
43 ppb emission limitation.
We request public comment on the proposed MACT floor level for
existing lean premix combustion turbines. We are particularly
interested in obtaining information on the annual/seasonal and
geographic variability in formaldehyde emissions that occur for lean
premix combustion turbines. Formaldehyde emission test reports that
were conducted over time for the same lean premix combustion turbine
would be especially helpful. We are also soliciting information
regarding the contribution of ambient formaldehyde to the variability
of outlet stack concentrations of formaldehyde.
4. MACT for Existing Lean Premix Combustion Turbines
To determine MACT for existing stationary lean premix combustion
turbines, we evaluated regulatory alternatives more stringent than the
MACT floor. For existing lean premix turbines, in terms of an emission
control technology which could serve as the basis for MACT, we
considered the use of an oxidation catalyst emission control device.
According to catalyst vendors, oxidation catalyst emission control is
being used on some existing lean premix combustion turbines, however,
we lack specific data regarding the performance of turbines with such
controls. The concentration of formaldehyde in the exhaust stream from
lean premix combustion turbines is already significantly lower than the
concentration of formaldehyde in the exhaust stream from diffusion
flame combustion turbines, and any reduction achieved by oxidation
catalyst control would be difficult to measure. Thus, we concluded that
the incremental cost per ton of HAP removed for that option is
excessive. We also considered the use of good operating practices to
reduce HAP emissions, but determined that we could not identify
specific good operating practices that would reduce HAP emissions.
Similarly, we also considered requiring the use of a particular fuel to
reduce HAP emissions but concluded that fuel switching would not result
in further HAP emissions reductions. As a result, we are proposing to
set MACT for existing lean premix combustion turbines at the MACT floor
(i.e., 43 ppbvd formaldehyde).

[[Page 1899]]

E. How Did We Determine the Basis and Level of the Proposed 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.
1. MACT Floor for New Diffusion Flame Combustion Turbines
To identify the MACT floor for new stationary combustion turbines
located at major sources, we consulted the inventory database and
oxidation catalyst vendor information. As mentioned earlier, oxidation
catalyst emission control devices are currently installed on about 3
percent of stationary diffusion flame combustion turbines. This 3
percent represents about 200 stationary combustion turbines. We also
considered whether the best controlled diffusion flame combustion
turbine might be using good operating practices or a particular fuel
that would reduce HAP emissions further and concluded, as we had
previously in this preamble for existing sources, that we could not
identify specific good operating practices that would reduce HAP
emissions, and that fuel switching would not result in further HAP
emissions reductions. We concluded, therefore, that the level of HAP
emission control achieved by the use of oxidation catalyst emission
control devices is the MACT floor for new stationary combustion
turbines.
After establishing this basis for the MACT floor, we determined the
level of performance based on the data available in the emissions
database. The emissions database, which is a compilation of available
HAP emission test reports, was created for the purpose of supporting
rulemaking for the proposed rule. The majority of HAP emission test
reports collected were conducted in California as part of the AB 2588
(Air Toxics ``Hot Spots'' Information Assessment Act of 1987) program.
Complete copies of HAP emission test reports for stationary combustion
turbines were gathered from all air districts in California and from
other sources, such as the EPA Source Test Information Retrieval System
(STIRS). Other States, including Washington, Texas, Pennsylvania, and
New Jersey, and trade associations such as the Western States Petroleum
Association (WSPA) and the Gas Research Institute (GRI) were also
contacted for available HAP emission test reports.
We then examined the emission control efficiency achieved by an
oxidation catalyst emission control device on a stationary combustion
turbine. We concluded that CO emission reductions are a good surrogate
for HAP emissions reductions for oxidation catalyst emission control
devices.
This conclusion that CO emission reductions are a good surrogate
for HAP emissions reductions achieved through the use of oxidation
catalyst emission control devices is also supported by data we have
collected from the use of oxidation catalyst emission control devices
on stationary reciprocating internal combustion engines (RICE). These
data from stationary RICE also show a direct relationship between CO
emission reductions and HAP emissions reductions. When oxidation
catalyst emission control devices are used to reduce CO emissions, they
will reduce HAP emissions.
The emissions database contains several emission test reports that
measured HAP and CO emissions from stationary combustion turbines, but
no emission test reports that measure the emission reduction efficiency
of an oxidation catalyst emission control device (measuring CO and HAP
emissions both before and after the control device). However, we
obtained information from a catalyst vendor for two tests for one
turbine. The results of those tests show that a CO reduction of 95 to
98 percent was achieved using an oxidation catalyst control system. We
reviewed the test report for the data to assure that the turbine was
operated correctly and that there was no turbine or control device
malfunction; we found no discrepancy. In addition to emissions testing
data, we reviewed design data from oxidation catalyst vendors for the
systems installed in the U.S. The typical emission reduction for
turbines that have been installed is 90 percent CO emission reduction,
with a few systems that are designed to be 95 percent or greater.
We reviewed other factors such as operator training in addition to
the control technology itself that could potentially result in better
emission reduction, but we found no effect of those factors on the
control efficiency. Based on the conclusions and data, we believe that
95 percent represents the level of control that can be achieved by the
best controlled similar source. As a result, we concluded that the
level of performance associated with the MACT floor (i.e., use of an
oxidation catalyst emission control device) is an emission reduction
efficiency of 95 percent or more for CO. The MACT floor for new
stationary diffusion flame combustion turbines is, therefore, a CO
emission reduction efficiency of 95 percent or more, using an oxidation
catalyst control system.
2. MACT for New Diffusion Flame Combustion Turbines
We were unable to identify any beyond-the-floor regulatory
alternatives for new stationary combustion turbines. We know of no
emission control technology currently available which can reduce HAP
emissions to levels lower than that achieved through the use of
oxidation catalyst emission control devices. Similarly, we know of no
work practice that could further reduce HAP emissions. In addition,
fuel switching will not result in further reductions of HAP emissions.
We concluded, therefore, that MACT for new diffusion flame stationary
combustion turbines is equivalent to the MACT floor. It should be noted
that the majority of new combustion turbines are expected to be lean
premix combustion turbines based on the significantly reduced emissions
of NO_X, CO, and formaldehyde. We estimate that less than 5
percent of new combustion turbines will be diffusion flame. Diesel-
fired combustion turbines cannot be operated in the lean premix mode,
and these turbines would have to install an oxidation catalyst system.
3. MACT Floor for New Lean Premix Combustion Turbines
To determine the MACT floor for new stationary lean premix
combustion turbines, we based our analysis on the same emissions data
for formaldehyde that we used for the existing MACT floor. The MACT
floor for existing lean premix combustion turbines is based on the
performance of the best performing lean premix combustion turbine; this
same level of performance can, therefore, be used to determine the MACT
floor for new lean premix combustion turbines. As discussed previously
in the existing source MACT, we believe that 43 ppbvd formaldehyde
represents the best performing turbine. The MACT floor for new lean
premix combustion turbines is, therefore, an emission limit of 43 ppbvd
formaldehyde.
4. MACT for New Lean Premix Combustion Turbines
To determine MACT for new stationary lean premix combustion
turbines, we evaluated regulatory alternatives more stringent than the
MACT floor. As with existing lean premix combustion turbines, we
considered the use of an oxidation catalyst control system. However,
although catalyst vendors have indicated that some existing lean

[[Page 1900]]

premix combustion turbines are using oxidation catalyst emission
control, we lack specific data regarding the performance of turbines
with such controls. The HAP concentration in the lean premix combustion
turbine exhaust is very low and, therefore, would be difficult to
measure if it were further reduced through the installation of an
oxidation catalyst. Due to the low HAP levels, the cost per ton of HAP
removed would be very high. We concluded, therefore, that MACT for new
stationary lean premix combustion turbines is equivalent to the MACT
floor.
5. MACT for Other Subcategories
Although the proposed rule would apply to all stationary combustion
turbines located at major sources of HAP emissions, emergency
stationary combustion turbines, limited use stationary combustion
turbines, stationary combustion turbines which fire landfill gas or
digester gas as their primary fuel, and stationary combustion turbines
of less than 1 MW rated peak power output are not required to meet the
emission limitations or operating limitations.
For each of the subcategories of stationary combustion turbines, as
mentioned earlier, 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.
Limited use stationary combustion turbines also operate
infrequently. As with emergency stationary combustion turbines, it is
this infrequent operation that limits the applicability of HAP emission
control technology.
Landfill and digester gases contain a family of silicon based gases
called siloxanes. Combustion of siloxanes forms compounds that can foul
post-combustion catalysts, rendering catalysts inoperable within a very
short time period. 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 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.
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 emissions reductions. The MACT floor, therefore, for each of
these subcategories is no emissions reduction.
Despite our concerns with the applicability of emission control
technology, we examined the cost per ton of HAP removed for these
subcategories. 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 nonair 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 nonair 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 emissions reductions 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 emissions reductions).

F. How Did We Select the Format of the Standard for New Diffusion Flame
Combustion Turbines?

We are proposing two options for complying with the standard for
new diffusion flame combustion turbines. You may reduce CO by 95
percent if you use an oxidation catalyst emission control device, or
reduce the concentration of formaldehyde in the exhaust from the
turbine to 43 ppb by volume or less, dry basis, at 15 percent oxygen.
We considered proposing an emission limitation for HAP, but are
proposing a CO emission reduction limitation as a surrogate for a HAP
emission limitation. We have decided to propose the use of the CO
emission reduction limitation as a surrogate for the HAP emission
limitation, because CO monitoring is currently being used by combustion
turbine owners and operators, it is significantly easier and less
expensive to measure and monitor CO than to measure and monitor each
HAP, and because we believe that CO reduction is a good measure of
performance of the oxidation catalyst emission control device.
Monitoring equipment for CO is readily available, which is not the case
for HAP monitoring equipment.
We are also proposing a percent reduction in CO emissions as the
emission limitation, rather than a single value for CO emissions. The
data upon which MACT are based show that while the level of CO
emissions entering an oxidation catalyst emission control device may
vary, the oxidation catalyst emission control device is able to
maintain a CO emission reduction efficiency of 95 percent or more.
We are also proposing an alternative emission limitation for
formaldehyde emissions. You may choose to comply with the emission
limitation for CO emission reduction (if you use an oxidation catalyst
emission control device) or you may choose to comply with the emission
limitation for formaldehyde emission concentration (if you use some
means other than an oxidation catalyst control device to reduce HAP
emissions). We would like to promote the development and eventual use
of alternative emission control technologies (including pollution
prevention technologies) to reduce HAP emissions, and we believe an
alternative emission limitation written in terms of formaldehyde
emissions will serve to do so. We are soliciting information on HAP and
CO emissions data from alternative emission control technologies during
the comment period. We are particularly interested in obtaining test
reports

[[Page 1901]]

where HAP and CO emissions reductions were measured with methods that
we are recommending to be used to measure HAP in the proposed rule.
For the emission limitation, we propose to use formaldehyde as a
surrogate for all HAP. Formaldehyde is the HAP emitted in the highest
concentrations from stationary combustion turbines. In addition, the
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 HAP emissions.
The emission limitation for formaldehyde is in units of parts per
billion, and all measurements must be corrected to 15 percent oxygen,
dry basis, to provide a common basis. A volume concentration was chosen
for the emission limitation because it can be measured directly.
We based the alternative emission limitation on the ability of lean
premix technology to reduce emissions to 43 ppbvd (at 15 percent
oxygen). The reduction in formaldehyde emissions is approximately
equivalent to that achieved when CO emissions are reduced by 95 percent
through the use of an oxidation catalyst emission control device.
As discussed later, we consider the cost of formaldehyde CEMS
excessive for the purpose of ensuring continuous compliance with this
emission limitation for formaldehyde emissions. As a result, we
selected stack emission testing to demonstrate compliance with the
emission limitation.

G. How Did We Select the Initial Compliance Requirements?

The emissions tests which form the basis of the proposed rule were
conducted using EPA or CARB test methods. The proposed rule requires
the use of these EPA or CARB test methods to determine compliance. This
ensures that the same procedures that were used to obtain the emission
data upon which the emission limitations are based are used for
compliance testing. By using the same test methods, we eliminate the
possibility of measurement bias and interference influencing
determinations of compliance.
For sources complying with the emission limitation to reduce CO
emissions, an initial performance evaluation is required. The
performance evaluation will validate performance of the CEMS. The
proposed rule also requires an annual relative accuracy test audit
(RATA) to ensure that performance of the CEMS does not deteriorate over
time. The first 4-hour period following this performance evaluation of
the CO CEMS will be used to determine initial compliance with the CO
emission reduction limitation.
New and reconstructed sources and existing lean premix combustor
turbines complying with the emission limitation to reduce 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.

H. 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 not required to develop a startup, shutdown or
malfunction plan since we do not believe meaningful procedures could be
developed.
We consider the use of CEMS the best means of ensuring continuous
compliance with emission limitations, and alternatives to CEMS are
considered only if we consider the use of a CEMS technically or
economically infeasible. For sources complying with the emission
limitation for CO emission reduction, we believe it is feasible to
require a CEMS because the costs for a CO CEMS are reasonable. Thus,
the proposed rule requires the use of a CO CEMS to continuously monitor
the reduction in CO emissions.
For sources complying with the emission limitation for formaldehyde
emissions, we also considered requiring a CEMS; however, we concluded
that the costs of a formaldehyde CEMS were excessive. 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 lean premix 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.
We request comments on the continued monitoring of stationary lean
premix combustion turbines that have demonstrated initial compliance.
The stationary lean premix combustion turbines are low NO_X
emitting and are permitted to continuously attain the permitted
NO_X levels. The same technology that results in the
maintenance of low NO_X levels is also related to the
achievement of low HAP emissions. Therefore, we would like to solicit
comments on the feasibility of requiring no additional testing or
monitoring after the lean premix stationary combustion turbine has
demonstrated initial compliance and is relying on the NO_X
permit levels, or low NO_X levels characteristic of lean
premix combustor turbines (e.g. NO_X levels guaranteed by the
manufacturer) if there are no permit levels, to assure continuing good
performance. We are proposing this in an attempt to streamline the
continuous testing, monitoring, and reporting requirements.
Finally, since we are unsure what new HAP emission control
technologies might emerge, we do not know whether it will be necessary
to establish additional operating limitations to ensure continuous
compliance with the formaldehyde emission limitation for sources that
are not lean premix or diffusion flame. Thus, as outlined earlier, the
proposed rule requires you to petition the Administrator for approval
of additional operating limitations or for approval of no additional
operating limitations.

I. How Did We Select the Monitoring and Testing Methods to Measure
These Low Concentrations of CO and Formaldehyde?

We believe CEMS are available which can measure CO emissions at the
low concentrations found in the exhaust from a stationary combustion
turbine following an oxidation catalyst emission control device. Our
performance specifications for CO CEMS (PS4 and PS4A), however, have
not been updated recently and do not reflect the performance
capabilities of such systems at these low CO concentration levels.
As a result, we solicit comments on the performance capabilities of
state-of-the-art CO CEMS and their ability to accurately measure the
low concentrations of CO experienced in the exhaust of a stationary
combustion turbine following an oxidation catalyst emission control
device. We also solicit comments with specific recommendations on the
changes we should make to our performance specifications for CO CEMS
(PS4 and PS4A) to ensure the installation and use of CEMS which can be
used to determine compliance with the proposed emission limitation for
CO emission reduction. In addition, we

[[Page 1902]]

solicit comments on the availability of instruments capable of meeting
the changes they recommend to our performance specifications for CO
CEMS.
Today's proposal specifies the use of Method 10 as the reference
method to certify the performance of the CO CEMS. We also believe
Method 10 is capable of measuring CO concentrations as low as those
experienced in the exhaust of a stationary combustion turbine following
an oxidation catalyst emission control device. However, the performance
criteria in addenda A of Method 10 have not been revised recently and
are not suitable for certifying the performance of a CO CEMS at these
low CO concentrations. Specifically, we believe the range and minimum
detectable sensitivity should be changed to reflect target
concentrations as low as 0.1 parts per million (ppm) CO in some cases.
We also expect that dual range instruments will be necessary to measure
CO concentrations at the inlet and at the outlet of an oxidation
catalyst emission control device.
As a result, we solicit comments with specific recommendations on
the changes we should make to Method 10 and the performance criteria in
addenda A. We also solicit comments on the availability of instruments
capable of meeting the changes they recommend to Method 10 and the
performance criteria in addenda A, while also meeting the remaining
addenda A performance criteria.
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 below 43
ppbvd. We expect path lengths in the range of 100 to 125 meters and
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 Method 320 and measure
formaldehyde concentrations at these low levels, we have limited
experience with their use. As a result, we solicit 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 emissions.
As an alternative to Method 320, we are proposing 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. We believe the
proposed method can measure low concentrations of formaldehyde at a
cost which is less than or equal to the cost of testing using Method
320; therefore, we solicit comments on the use of Method 323 by natural
gas-fired sources to demonstrate compliance with the formaldehyde
emission limitation.
We also believe CARB Method 430 and EPA SW-846 Method 0011 are
capable of measuring formaldehyde concentrations at these low levels.
Accordingly, we solicit comments on the use of CARB 430 and EPA SW-846
Method 0011 to determine compliance with the emission limitations for
formaldehyde.
Based on the comments we receive on CO CEMS, we anticipate revising
Method 10 and our performance specifications (PS4 and PS4A) for CO CEMS
to ensure the installation and use of CEMS suitable for determining
compliance with the emission limitation for CO emission reduction. If
we should promulgate today's proposed rule for stationary combustion
turbines before completing these revisions, however, we may require all
new and reconstructed stationary combustion turbines subject to the
final rule to demonstrate compliance with the formaldehyde emission
limitation, or a formaldehyde percent reduction limitation similar to
the CO percent reduction emission limitation, until we have adopted
final revisions to Method 10 and our performance specifications for CO
CEMS.
On the other hand, if the comments we receive lead us to conclude
that CO CEMS are not capable of being used to determine compliance with
the emission limitation for CO emission reduction, there are several
alternatives we may consider. One alternative would be to delete the
proposed percent reduction emission limitation for CO and require
compliance with a comparable formaldehyde percent reduction limitation.
This alternative would require periodic stack emission testing before
and after the control device and would also require owners and
operators to petition the Administrator for additional operating
limitations, as proposed today for those choosing to comply with the
emission limitation for formaldehyde. Another alternative would be to
delete the proposed emission limitation for CO emission reduction and
require compliance with the proposed emission limitation for
formaldehyde. This alternative could require more frequent emission
testing and could also require owners and operators to petition the
Administrator for additional operating limitations.
Another alternative would be to require the use of Method 320
(i.e., FTIR systems) to determine compliance with the emission
limitation for CO emission reduction. This alternative could also
require more frequent emission testing and require owners and operators
to petition the Administrator for additional operating limitations, as
proposed today for those choosing to comply with the emission
limitation for formaldehyde.
Based on the comments we receive on FTIR systems and Method 320, we
may develop additional or revised criteria for the use of FTIR systems
and/or Method 320 to determine compliance with the emission limitation
for formaldehyde.
If we should conclude that neither CO CEMS or FTIR systems are
capable of being used to determine compliance with the emission
limitations for CO or formaldehyde emissions, then we may delete the
emission limitations for CO and formaldehyde emissions and adopt an
emission limitation consisting of an equipment and work practice
requirement. This alternative would require the use of oxidation
catalyst emission control devices which meet specific and narrow design
and operating criteria.
We believe the emission limitations we are proposing for CO
emission reduction and formaldehyde emission concentration are superior
to these alternatives for a number of reasons. We believe that the CO
emission limitation is better because it is easier and cheaper to
continuously monitor CO, and it has been shown to be a good surrogate
for HAP. Also, we prefer to have an emission limitation rather than an
equipment or work practice standard. An emission limitation is superior
because it ensures that emissions are below a certain level, as
demonstrated by a CEMS or performance testing. However, we solicit
comments on these alternatives, should we conclude that the proposed
emission limitations for CO emission reduction and formaldehyde
emission concentration are inappropriate because of difficulties in
monitoring or measuring CO emission reduction or formaldehyde emission
concentration to determine compliance. We also solicit suggestions and
recommendations for other alternatives, should we conclude the proposed
emission limitations are inappropriate because of monitoring or
measurement difficulties.

[[Page 1903]]

J. How Did We Select the Notification, Recordkeeping and Reporting
Requirements?

The proposed notification, recordkeeping, and reporting
requirements are based on the NESHAP General Provisions of 40 CFR part
63.

IV. Summary of Environmental, Energy and Economic Impacts

We estimate that 20 percent of the stationary combustion turbines
affected by the proposed rule will be located at major sources. As a
result, the environmental, energy, and economic impacts presented in
this preamble reflect these estimates.

A. What Are the Air Quality Impacts?

The proposed rule will reduce total national HAP emissions by an
estimated 81 tons/year in the 5th year after the standards are
promulgated. The emissions reductions achieved by the proposed rule
would be due to the sources that install an oxidation catalyst control
system. We estimate that about 10 existing lean premix combustion
turbines will install oxidation catalyst control to comply with the
standard. In addition, we estimate that about 5 percent of new
stationary combustion turbines will install oxidation catalyst control
to comply with the standards. The other 95 percent of new stationary
combustion turbines will be lean premix, a pollution prevention
technology which in most cases does not require the use of oxidation
catalyst control. The lean premix turbines are currently being
installed to meet NO_X emission standards. The reduction of
HAP emissions for these stationary combustion turbines is difficult to
assess because it is a pollution prevention technology and is being
installed to meet NO_X limits, not as a result of MACT for
stationary combustion turbines. Therefore, as stated previously, the
HAP emissions reductions obtained by the proposed rule result only from
the sources that install an oxidation catalyst control system.
To estimate air impacts, national HAP emissions in the absence of
the proposed rule (i.e., HAP emission baseline) were calculated using
an emission factor from the emissions database. We assumed new
stationary combustion turbines are operated 8,760 hours annually. We
then assumed a HAP reduction of 95 percent, achieved by using oxidation
catalyst emission control devices to comply with the emission
limitation to reduce CO emissions, 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 emission reductions.
In addition to HAP emission reductions, the proposed rule will reduce
criteria air pollutant emissions, primarily CO emissions.

B. What Are the Cost Impacts?

The national total annualized cost of the proposed rule in the 5th
year following promulgation is estimated to be about $21.5 million.
Approximately $267,500 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 over the next 5 years
is based on review of permit data gathered by EPA from 1998 to the
present time, confidential projection data from turbine manufacturers,
and published sales data. We believe this projection is a reasonable
estimate based on the available information.

C. What Are the Economic Impacts?

The EPA prepared an economic impact analysis to evaluate the
impacts the proposed rule would have on the combustion turbines
producers, consumers of goods and services produces by combustion
turbines, and society. The analysis shows minimal changes in prices and
output for products made by the 24 industries affected by the proposed
rule. The price increase for affected output is less than 0.01 percent
and the reduction in output is less than 0.01 percent for each affected
industry. Estimates of impacts on fuel markets show price increases of
less than 0.012 percent for petroleum products and natural gas, and
price increases of 0.13 and 0.17 percent for base-load and peak-load
electricity, respectively. The price of coal is expected to decline by
about 0.06 percent, and this is due to a small reduction in demand for
this fuel type. Reductions in output are expected to be less than 0.16
percent for each energy type, including base-load and peak-load
electricity. The social costs of the proposed rule are estimated at
$13.3 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
resulting from 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 proposed rule
on them lead to the estimated social costs being somewhat less than the
total annualized compliance cost estimate of $21.5 million (1998$). The
primary reason for the much 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 Nonair 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 nonair environmental or
health impacts as a result of the implementation of the rule as
proposed.

V. Solicitation of Comments and Public Participation

A. General

We are requesting comments on the proposed rule. We request
comments on all aspects of the proposed rule, such as the proposed
emission limitations and operating limitations, recordkeeping and
monitoring requirements, as well as aspects you may feel have not been
addressed.
Specifically, we request comments on the performance capabilities
of state-of-the-art CO CEMS and their ability to measure the low
concentrations of CO in the exhaust of a stationary combustion turbine
following an oxidation catalyst emission control device. We also
request comments with recommendations on changes commenters believe we
should make to our performance specifications for CO CEMS (PS4 and
PS4A) of 40 CFR part 60, appendix B, and to Method 10 of 40 CFR part
60, appendix A, and the performance criteria in addenda A to Method 10.
In addition, we request comments from these commenters on the
availability of instruments capable of meeting the changes they
recommend to our performance specifications for CO CEMS (PS4 and PS4A)
of 40 CFR part 60, Method 10 of 40 CFR part 60,

[[Page 1904]]

appendix A, and addenda A to method 10.
As also mentioned earlier, we request comments on the ability and
use of FTIR systems to meet the validation and quality assurance
requirements of Method 320 of 40 CFR part 63, appendix A, for the
purpose of determining compliance with the emission limitation for
formaldehyde emissions. In addition, we request comments on the use of
Method 323 of 40 CFR part 63, appendix A, SW-846 Method 0011, and CARB
430 to determine compliance with the emission limitations for
formaldehyde.
We request any HAP emissions test data available from stationary
combustion turbines; however, if you submit HAP emissions test data,
please submit the full and complete emission test report with this
data. Without a complete emission test report, which includes sections
describing the stationary combustion turbine and its operation during
the test as well as identifying the stationary combustion turbine for
purposes of verification, discussion of the test methods employed and
the Quality Assurance/Quality Control (QA/QC) procedures followed, the
raw data sheets, all the calculations, etc., which such reports
contain, submittal of HAP emission data by itself is of little use.

B. Can We Achieve the Goals of the Proposed Rule in a Less Costly
Manner?

We have made every effort in developing the proposal to minimize
the cost to the regulated community and allow maximum flexibility in
compliance options consistent with our statutory obligations. We
recognize, however, that the proposal may still require some facilities
to take costly steps to further control emissions even though those
emissions may not result in exposures which could pose an excess
individual lifetime cancer risk greater than one in 1 million or exceed
thresholds determined to provide an ample margin of safety for
protecting public health and the environment from the effects of HAP.
We also recognize that in some cases the proposal may require
facilities to undertake emissions testing and monitoring even when the
rule will not require them to reduce emissions at all. However, this is
necessary to assure the proper initial performance and continuing
performance of the emission reduction-pollution prevention technology.
We are, therefore, specifically soliciting comment on whether there are
further ways to structure the proposed 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.
Representatives of the plywood and composite wood products industry
provided EPA with descriptions of three mechanisms that they believed
could be used to implement more cost-effective reductions in risk. The
docket for today's proposed rule contains white papers prepared by the
plywood and composite wood products industry that outline their
proposed approaches (see docket OAR-2002-0060). These approaches could
be effective in focusing regulatory controls on facilities that pose
significant risks and avoiding the imposition of high costs on
facilities that pose little risk to public health or the environment,
and we are seeking public comment on the utility of each of these
approaches with respect to the proposed rule.
One of the approaches, an applicability cutoff for threshold
pollutants, would be implemented under the authority of CAA section
112(d)(4); the second approach, subcategorization and delisting, would
be implemented under the authority of CAA sections 112(c)(1) and
112(c)(9); and the third approach would involve the use of a
concentration-based applicability threshold. We are seeking comment on
whether these approaches are legally justified and, if so, we ask for
information that could be used to support such approaches. In addition,
on August 21, 2002, the Agency received a petition from the Gas Turbine
Association (GTA) requesting that natural gas fueled combustion
turbines be delisted and a study that they believed would justify
delisting. Section 112(c)(9) of the CAA provides EPA with the authority
to delist categories or subcategories either in response to the
petition of any person or upon the Administrator's own motion. The GTA
states that the study supports a determination that HAP emissions from
gas turbines would not result in a lifetime cancer risk greater than
one in a million to the individual in the population most exposed to
the emissions or non-carcinogenic health risk exceeding a level which
is adequate to protect public health with an ample margin of safety. We
have reviewed the GTA study and responded to the GTA on October 11,
2002 with questions and areas that we believe need further analysis.
The EPA's request for further information and all information provided
by the petitioner to date is located in the docket for today's proposed
rule.
The MACT program outlined in CAA section 112(d) is intended to
reduce emissions of HAP through the application of MACT to major
sources of toxic air pollutants. Section 112(c)(9) is intended to allow
EPA to avoid setting MACT standards for sources or subcategories of
sources that pose less than a specified level of risk to public health
and the environment. The EPA requests comment on whether the proposals
described here appropriately coordinate these provisions of CAA section
112. The two health-based approaches focus on assessing inhalation
exposures or accounting for adverse environmental impacts. EPA
specifically requests comment on the appropriateness and necessity of
extending these approaches to account for non-inhalation exposures of
certain HAP which may deposit from the atmosphere after being emitted
into the air or to account for adverse environmental impacts. In
addition to the specific requests for comment noted in this section, we
are also interested in any information or comment concerning technical
limitations, environmental and cost impacts, compliance assurance,
legal rationale, and implementation relevant to the identified
approaches. We also request comment on appropriate practicable and
verifiable methods to ensure that sources' emissions remain below
levels that protect public health and the environment. We will evaluate
all comments before determining whether to include an approach in the
final rule.
1. Industry HAP Emissions and Potential Health Effects
For the stationary combustion turbines source category, four HAP
account for essentially all of the mass of HAP emissions. Those four
HAP are formaldehyde, toluene, benzene, and acetaldehyde. Additional
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, acrolein, ethylbenzene, naphthalene, polycyclic aromatic
hydrocarbons (PAH), propylene oxide, and xylenes. The following
metallic HAP emissions have been measured from distillate oil fired
stationary combustion turbines: arsenic, beryllium, cadmium, chromium,
lead, manganese, mercury, nickel, and selenium.
Of the four HAP emitted in the largest quantities by this source
category, all can cause toxic effects following sufficient exposure.
The potential toxic effects of these four HAP are discussed previously
in this preamble.
In accordance with section 112(k), EPA developed a list of 33 HAP
which present the greatest threat to public

[[Page 1905]]

health in the largest number of urban areas. Of the four predominant
HAP, three (acetaldehyde, benzene, and formaldehyde) are included on
this list for the EPA's Urban Air Toxics Program. Eleven of the other
emitted HAP (acrolein, arsenic compounds, beryllium compounds, 1,3-
butadiene, cadmium compounds, chromium compounds, lead compounds,
manganese compounds, mercury compounds, nickel compounds, and PAH (as
POM)) also appear on the list. In November 1998, EPA published ``A
Multimedia Strategy for Priority Persistent, Bioaccumulative, and Toxic
(PBT) Pollutants.'' None of the predominant four HAP emitted by
stationary combustion turbine operations appears on the published list
of compounds referred to in the EPA's PBT strategy. Three of the other
HAP (mercury compounds, cadmium compounds, and PAH) appear on the list.
Of the HAP emitted by stationary combustion turbine operations,
fifteen (acetaldehyde, acrolein, arsenic compounds, benzene, beryllium
compounds, 1,3-butadiene, cadmium compounds, chromium compounds,
formaldehyde, lead compounds, mercury compounds, naphthalene, nickel
compounds, PAH, and propylene oxide) are carcinogens that, at present,
are not considered to have thresholds for cancer effects. Formaldehyde,
however, is a potential threshold carcinogen, and EPA is currently
revising the dose-response assessment for formaldehyde.
2. Applicability Cutoffs for Threshold Pollutants Under Section
112(d)(4) of the CAA
The first approach is an applicability cutoff for threshold
pollutants that is based on EPA's authority under CAA section 112(d)(4)
to establish standards for HAP which are threshold pollutants. A
threshold pollutant is one for which there is a concentration or dose
below which adverse effects are not expected to occur over a lifetime
of exposure. For such pollutants, CAA section 112(d)(4) allows EPA to
consider the threshold level, with an ample margin of safety, when
establishing emissions standards. Specifically, CAA section 112(d)(4)
allows EPA to establish emission standards that are not based upon the
MACT specified under CAA section 112(d)(2) for pollutants for which a
health threshold has been established. Such standards may be less
stringent than MACT. Historically, EPA has interpreted CAA section
112(d)(4) to allow categories of sources that emit only threshold
pollutants to avoid further regulation if those emissions result in
ambient levels that do not exceed the threshold, with an ample margin
of safety.\2\
---------------------------------------------------------------------------

\2\ See 63 FR 18754, 18765-66 (April 15, 1998) (Pulp and Paper
Sources Proposed NESHAP)
---------------------------------------------------------------------------

A different interpretation would allow us to exempt individual
facilities within a source category that meet the CAA section 112(d)(4)
requirements. There are three potential scenarios under this
interpretation of the CAA section 112(d)(4) provision. One scenario
would allow an exemption for individual facilities that emit only
threshold pollutants and can demonstrate that their emissions of
threshold pollutants would not result in air concentrations above the
threshold levels, with an ample margin of safety, even if the category
is otherwise subject to MACT. A second scenario would allow the CAA
section 112(d)(4) provision to be applied to both threshold and non-
threshold pollutants, using the one in a million cancer risk level for
decisionmaking for non-threshold pollutants.
A third scenario would allow a CAA section 112(d)(4) exemption at a
facility that emits both threshold and non-threshold pollutants. For
those emission points where only threshold pollutants are emitted and
where emissions of the threshold pollutants would not result in air
concentrations above the threshold levels, with an ample margin of
safety, those emission points could be exempt from the MACT standards.
The MACT standards would still apply to non-threshold emissions from
other emission points at the source. For this third scenario, emission
points that emit a combination of threshold and nonthreshold pollutants
that are co-controlled by MACT would still be subject to the MACT level
of control. However, any threshold HAP eligible for exemption under CAA
section 112(d)(4) that are controlled by control devices different from
those controlling nonthreshold HAP would be able to use the exemption,
and the facility would still be subject to the parts of the standards
that control non-threshold pollutants or that control both threshold
and non-threshold pollutants.
a. Estimation of hazard quotients and hazard indices. Under the CAA
section 112(d)(4) approach, EPA would have to determine that emissions
of each of the threshold pollutants emitted by stationary combustion
turbines at the facility do not result in exposures which exceed the
threshold levels, with an ample margin of safety.The common approach
for evaluating the potential hazard of a threshold air pollutant is to
calculate a hazard quotient by dividing the pollutant's inhalation
exposure concentration (often assumed to be equivalent to its estimated
concentration in air at a location where people could be exposed) by
the pollutant's inhalation Reference Concentration (RfC). An RfC is an
estimate (with uncertainty spanning perhaps an order of magnitude) of a
continuous inhalation exposure that, over a lifetime, likely would not
result in the occurrence of adverse health effects in humans, including
sensitive individuals.
The EPA typically establishes an RfC by applying uncertainty
factors to the critical toxic effect derived from the lowest- or no-
observed-adverse-effect level of a pollutant.\3\ A hazard quotient less
than one means that the exposure concentration of the pollutant is less
than the RfC, and, therefore, presumed to be without appreciable risk
of adverse health effects. A hazard quotient greater than one means
that the exposure concentration of the pollutant is greater than the
RfC. Further, EPA guidance for assessing exposures to mixtures of
threshold pollutants recommends calculating a hazard index (HI) by
summing the individual hazard quotients for those pollutants in the
mixture that affect the same target organ or system by the same
mechanism.\4\ The HI values would be interpreted similarly to hazard
quotients; values below one would generally be considered to be without
appreciable risk of adverse health effects, and values above one would
generally be cause for concern.
---------------------------------------------------------------------------

\3\ ``Methods for Derivation of Inhalation Reference
Concentrations and Applications of Inhalation Dosimetry.'' EPA-600/
8-90-066F, Office of Research and Development, USEPA, October 1994.
\4\ ``Supplementary Guidance for Conducting Health Risk
Assessment of Chemical Mixtures. Risk Assessment Forum Technical
Panel,'' EPA/630/R-00/002. USEPA, August 2000. http://www.epa.gov/nceawww1/pdfs/chem_mix/chem_mix08_2001.pdf.₂
---------------------------------------------------------------------------

For the determinations discussed herein, EPA would generally plan
to use RfC values contained in EPA's toxicology database, the
Integrated Risk Information System (IRIS). When a pollutant does not
have an approved RfC in IRIS, or when a pollutant is a carcinogen, EPA
would have to determine whether a threshold exists based upon the
availability of specific data on the pollutant's mode or mechanism of
action, potentially using a health threshold value from an alternative
source such as the Agency for Toxic Substances and Disease Registry
(ATSDR) or the California Environmental Protection Agency (CalEPA).
Table 3 provides RfC, as well as unit risk estimates, for the HAP
emitted by

[[Page 1906]]

combustion turbine operations. A unit risk estimate is defined as the
upper-bound excess lifetime cancer risk estimated to result from
continuous exposure to an agent at a concentration of 1 ug/m\3\ in the
air.

Table 3.--Dose-Response Assessment Values for HAP Reported Emitted by the Combustion Turbine Source Category
----------------------------------------------------------------------------------------------------------------
Reference concentration Unit risk estimate \b\ (1/
Chemical name CAS No. \a\ (mg/m\3\) (ug/m\3\))
----------------------------------------------------------------------------------------------------------------
Acetaldehyde...................... 75-07-0 9.0E-03 IRIS 2.2E-06 IRIS
Acrolein.......................... 107-02-8 2.0E-05 IRIS .........................
Arsenic compounds................. 7440-38-2 3.0E-05 CAL 4.3E-03 IRIS
Benzene........................... 71-43-2 6.0E-02 CAL 7.8E-06 IRIS
Beryllium compounds............... 7440-41-7 2.0E-05 IRIS 2.4E-03 IRIS
1,3-Butadiene..................... 106-99-0 2.0E-03 IRIS 3.0E-05 EPA ORD
Cadmium compounds................. 7440-43-9 2.0E-05 IRIS 1.8E-03 IRIS
Chromium (VI) compounds........... 18540-29-9 1.0E-04 IRIS 1.2E-02 IRIS
Ethyl benzene..................... 100-41-4 1.0E+00 IRIS
Formaldehyde...................... 50-00-0 9.8E-03 ATSDR 1.3E-05 IRIS
Lead compounds.................... 7439-92-1 ......................... 1.2E-05 CAL
Manganese compounds............... 7439-96-5 5.0E-05 IRIS .........................
Mercury compounds................. HG--CMPDS 9.0E-05 CAL .........................
Naphthalene....................... 91-20-3 3.0E-03 IRIS .........................
Nickel compounds.................. 7440-02-0 2.0E-04 ATSDR 9.1E-01 CAL
PAH (shown below as 7-PAH)........ ...................... ......................... .........................
Benzo (a) anthracene.............. 56-55-3 ......................... 1.1E-04 CAL
Benzo (b) fluoranthene............ 205-99-2 ......................... 1.1E-04 CAL
Benzo (k) fluoranthene............ 207-08-9 ......................... 1.1E-04 CAL
Benzo (a) pyrene.................. 50-32-8 ......................... 1.1E-03 CAL
Chrysene.......................... 218-01-9 ......................... 1.1E-05 CAL
Dibenz (a,h) anthracene........... 53-70-3 ......................... 1.2E-03 CAL
Indeno (1,2,3-cd) pyrene.......... 193-39-5 . 1.4E-04 CAL
Propylene oxide................... 75-56-9 3.0E-02 IRIS 3.7E-06 IRIS
Selenium compounds................ 7782-49-2 2.0E-02 CAL .........................
Toluene........................... 108-88-3 4.0E-01 IRIS .........................
Xylenes (mixed)................... 1330-20-7 4.3E-01 ATSDR .........................
----------------------------------------------------------------------------------------------------------------
\a\ Reference Concentration: An estimate (with uncertainty spanning perhaps an order of magnitude) of a
continuous inhalation exposure to the human population (including sensitive subgroups which include children,
asthmatics, and the elderly) that is likely to be without an appreciable risk of deleterious effects during a
lifetime. It can be derived from various types of human or animal data, with uncertainty factors generally
applied to reflect limitations of the data used.
\b\ Unit Risk Estimate: The upper-bound excess lifetime cancer risk estimated to result from continuous exposure
to an agent at a concentration of 1 ug/m\3\ in air. The interpretation of the Unit Risk Estimate would be as
follows: If the Unit Risk Estimate = 1.5 x 10-6 per ug/m\3\, 1.5 excess tumors are expected to develop per
1,000,000 people if exposed daily for a lifetime to 1 ug of the chemical in 1 cubic meter of air. Unit Risk
Estimates are considered upper bound estimates, meaning they represent a plausible upper limit to the true
value. (Note that this is usually not a true statistical confidence limit.) The true risk is likely to be
less, but could be greater.
Sources:
IRIS = EPA Integrated Risk Information System (http://www.epa.gov/iris/subst/index.html).
ATSDR = U.S. Agency for Toxic Substances and Disease Registry (http://www.atsdr.cdc.gov/mrls.html).
CAL = California Office of Environmental Health Hazard Assessment. (http://www.oehha.ca.gov/air/hot_spots/index.html).
HEAST = EPA Health Effects Assessment Summary Tables (#PB(=97-921199, July 1997).

To establish an applicability cutoff under CAA section 112(d)(4),
EPA would need to define ambient air exposure concentration limits for
any threshold pollutants involved. There are several factors to
consider when establishing such concentrations. First we would need to
ensure that the concentrations that would be established would protect
public health with an ample margin of safety. As discussed above, the
approach EPA commonly uses when evaluating the potential hazard of a
threshold air pollutant is to calculate the pollutant's hazard
quotient, which is the exposure concentration divided by the RfC. The
EPA's ``Supplementary Guidance for Conducting Health Risk Assessment of
Chemical Mixtures'' suggests that the noncancer health effects
associated with a mixture of pollutants ideally are assessed by
considering the pollutants' common mechanisms of toxicity \5\. The
guidance also suggests that when exposures to mixtures of pollutants
are being evaluated, the risk assessor may calculate a HI. The
recommended method is to calculate multiple hazard indices for each
exposure route of interest, and for a single specific toxic effect or
toxicity to a single target organ. The default approach recommended by
the guidance is to sum the hazard quotients for those pollutants that
induce the same toxic effect or affect the same target organ. A mixture
is then assessed by several HI, each representing one toxic effect or
target organ. The guidance notes that the pollutants included in the HI
calculation are any pollutants that show the effect being assessed,
regardless of the critical effect upon which the RfC is based. The
guidance cautions that if the target organ or toxic effect for which
the HI is calculated is different from the RfC's critical effect, then
the RfC for that chemical will be an overestimate, that is, the
resultant HI potentially may be overprotective. Conversely, since the
calculation of a HI does not account for the fact that the potency of a
mixture of HAP can be more potent than the sum of the individual HAP
potencies, a HI may potentially be underprotective in some situations.
---------------------------------------------------------------------------

\5\ ibid.

---------------------------------------------------------------------------

[[Page 1907]]

b. Options for establishing a HI limit. One consideration in
establishing a HI limit is whether the analysis considers the total
ambient air concentrations of all the emitted HAP to which the public
is exposed \6\. There are several options for establishing a HI limit
for the Sec. 112(d)(4) analysis that reflect, to varying degrees,
public exposure.
---------------------------------------------------------------------------

\6\ Senate Debate on Conference Report (October 27, 1990),
reprinted in ``A Legislative History of the Clean Air Act Amendments
of 1990,'' Comm. Print S. Prt. 103-38 (1993) (``Legis. Hist.'') at
868.
---------------------------------------------------------------------------

One option is to allow the hazard index posed by all threshold HAP
emitted by combustion turbines at the facility to be no greater than
one. This approach is protective if no additional threshold HAP
exposures would be anticipated from other sources at, or in the
vicinity of, the facility or through other routes of exposure (i.e.,
through ingestion).
A second option is to adopt a default percentage approach, whereby
the HI limit of the HAP emitted by the facility is set at some
percentage or fraction of one (e.g., 20 percent or 0.2). This approach
recognizes the fact that the facility in question is only one of many
sources of threshold HAP to which people are typically exposed every
day. Because noncancer risk assessment is predicated on total exposure
or dose, and because risk assessments focus only on an individual
source, establishing a HI limit of 0.2 would account for an assumption
that 20 percent of an individual's total exposure is from that
individual source. For the purposes of this discussion, we will call
all sources of HAP, other than operations within the source category at
the facility in question, ``background'' sources. If the affected
source is allowed to emit HAP such that its own impacts could result in
HI values of one, total exposures to threshold HAP in the vicinity of
the facility could be substantially greater than one due to background
sources, and this would not be protective of public health, since only
HI values below one are considered to be without appreciable risk of
adverse health effects. Thus, setting the HI limit for the facility at
some default percentage of one will provide a buffer which would help
to ensure that total exposures to threshold HAP near the facility
(i.e., in combination with exposures due to background sources) will
generally not exceed one, and can generally be considered to be without
appreciable risk of adverse health effects.
The EPA requests comment on using the default percentage approach
and on setting the default HI limit at 0.2. The EPA is also requesting
comment on whether an alternative HI limit, in some multiple of one,
would be a more appropriate applicability cutoff.
A third option is to use available data (from scientific literature
or EPA studies, for example) to determine background concentrations of
HAP, possibly on a national or regional basis. These data would be used
to estimate the exposures to HAP from non-combustion turbine sources in
the vicinity of an individual facility. For example, EPA's National
Scale Air Toxics Assessment (NATA) \7\ and ATSDR's Toxicological
Profiles \8\ contain information about background concentrations of
some HAP in the atmosphere and other media. The combined exposures from
an affected source and from background emissions (as determined from
the literature or studies) would then not be allowed to exceed a HI
limit of 1. The EPA requests comment on the appropriateness of setting
the hazard index limit at one for such an analysis.
---------------------------------------------------------------------------

\7\ See http://www.epa.gov/ttn/atw/nata.
\8\ See http://www.atsdr.cdc.gov/toxpro2.html.
---------------------------------------------------------------------------

A fourth option is to allow facilities to estimate or measure their
own facility-specific background HAP concentrations for use in their
analysis. With regard to the third and fourth options, EPA requests
comment on how these analyses could be structured. Specifically, EPA
requests comment on how the analyses should take into account
background exposure levels from air, water, food and soil encountered
by the individuals exposed to emissions from this source category. In
addition, we request comment on how such analyses should account for
potential increases in exposures due to the use of a new HAP or the
increased use of a previously emitted HAP, or the effect of other
nearby sources that release HAP.
The EPA requests comment on the feasibility and scientific validity
of each of these or other options. Finally, EPA requests comment on how
we should implement the CAA section 112(d)(4) applicability cutoffs,
including appropriate mechanisms for applying cutoffs to individual
facilities. For example, would the title V permit process provide an
appropriate mechanism?
c. Tiered analytical approach for predicting exposure. Establishing
that a facility meets the cutoffs established under CAA section
112(d)(4) will necessarily involve combining estimates of pollutant
emissions with air dispersion modeling to predict exposures. The EPA
envisions that we would promote a tiered analytical approach for these
determinations. A tiered analysis involves making successive
refinements in modeling methodologies and input data to derive
successively less conservative, more realistic estimates of pollutant
concentrations in air and estimates of risk.
As a first tier of analysis, EPA could develop a series of simple
look-up tables based on the results of air dispersion modeling
conducted using conservative input assumptions. By specifying a limited
number of input parameters, such as stack height, distance to property
line, and emission rate, a facility could use these look-up tables to
determine easily whether the emissions from their sources might cause a
hazard index limit to be exceeded.
A facility that does not pass this initial conservative screening
analysis could implement increasingly more site-specific but more
resource-intensive tiers of analysis using EPA-approved modeling
procedures, in an attempt to demonstrate that their facility does not
exceed the HI limit. Existing EPA guidance could provide the basis for
conducting such a tiered analysis. \9\
---------------------------------------------------------------------------

\9\ ``A Tiered Modeling Approach for Assessing the Risks due to
Sources of Hazardous Air Pollutants.'' EPA-450/4-92-001. David E.
Guinnup, Office of Air Quality Planning and Standards, USEPA, March
1992.
---------------------------------------------------------------------------

The EPA requests comment on methods for constructing and
implementing a tiered analysis for determining applicability of the CAA
section 112(d)(4) criterion to specific combustion turbine sources.
Ambient monitoring data could possibly be used to supplement or
supplant the tiered modeling analysis described above. We envision that
the appropriate monitoring to support such a determination could be
extensive. The EPA requests comment on the appropriate use of
monitoring in the determinations described above.
d. Accounting for dose-response relationships. In the past, EPA
routinely treated carcinogens as nonthreshold pollutants. The EPA
recognizes that advances in risk assessment science and policy may
affect the way EPA differentiates between threshold and nonthreshold
HAP. The EPA's draft Guidelines for Carcinogen Risk Assessment \10\
suggest that carcinogens be assigned non-linear dose-response
relationships where data warrant. Moreover, it is possible that dose-
response curves for some pollutants may reach zero risk at a dose
greater

[[Page 1908]]

than zero, creating a threshold for carcinogenic effects. It is
possible that future evaluations of the carcinogens emitted by this
source category would determine that one or more of the carcinogens in
the category is a threshold carcinogen or is a carcinogen that exhibits
a non-linear dose-response relationship but does not have a threshold.
---------------------------------------------------------------------------

\10\ ``Draft Revised Guidelines for Carcinogen Risk
Assessment.'' NCEA-F-0644, USEPA, Risk Assessment Forum, July 1999.
pp 3-9ff. http://www.epa.gov/ncea/raf/pdfs/cancer_gls.pdf.
---------------------------------------------------------------------------

The dose-response assessment for formaldehyde is currently
undergoing revision by EPA. As part of this revision effort, EPA is
evaluating formaldehyde as a potential non-linear carcinogen. The
revised dose-response assessment will be subject to review by the EPA
Science Advisory Board, followed by full consensus review, before
adoption into the EPA IRIS. At this time, EPA estimates that the
consensus review will be completed by the end of 2003. The revision of
the dose-response assessment could affect the potency factor of
formaldehyde, as well as its status as a threshold or nonthreshold
pollutant. At this time, the outcome is not known. In addition to the
current reassessment by EPA, there have been several reassessments of
the toxicity and carcinogenicity of formaldehyde in recent years,
including work by the World Health Organization and the Canadian
Ministry of Health.
The EPA requests comment on how we should consider the state of the
science as it relates to the treatment of threshold pollutants when
making determinations under CAA section CAA section 112(d)(4). In
addition, EPA requests comment on whether there is a level of emissions
of a non-threshold carcinogenic HAP at which it would be appropriate to
allow a facility to use the scenarios discussed under the CAA section
112(d)(4) approach.
If the CAA section 112(d)(4) approach were adopted, the
requirements of the rule as proposed would not apply to any source that
demonstrates, based on a tiered analysis that includes EPA-approved
modeling of the affected source's emissions, that the anticipated HAP
exposures do not exceed the specified HI limit.
3. Subcategory Delisting Under Section 112(c)(9)(B) of the CAA
The EPA is authorized to establish categories and subcategories of
sources, as appropriate, pursuant to CAA section 112(c)(1), in order to
facilitate the development of MACT standards consistent with section
112 of the CAA. Further, section CAA section 112(c)(9)(B) allows EPA to
delete a category (or subcategory) from the list of major sources for
which MACT standards are to be developed when the following can be
demonstrated: (1) In the case of carcinogenic pollutants, that ``no
source in the category * * * emits [carcinogenic]
air pollutants in
quantities which may cause a lifetime risk of cancer greater than one
in 1 million to the individual in the population who is most exposed to
emissions of such pollutants from the source''; (2) in the case of
pollutants that cause adverse noncancer health effects, that
``emissions from no source in the category or subcategory * * * exceed
a level which is adequate to protect public health with an ample margin
of safety''; and (3) in the case of pollutants that cause adverse
environmental effects, that ``no adverse environmental effect will
result from emissions from any source.''
One way in which the Agency could use these authorities would be to
define a subcategory of facilities within the source category based
upon technological differences, such as differences in turbine design
characteristics, fuel type, production rate, emission vent flow rates,
overall facility size, emissions characteristics, processes, or air
pollution control device viability. The EPA requests comment on how we
might establish subcategories based on these, or other, source
characteristics. If it could then be determined that each source in
this technologically-defined subcategory presents a low risk to the
surrounding community, the subcategory could then be delisted in
accordance with CAA section 112(c)(9). The GTA letter discussed above
provides two examples of technological differences that may allow us to
create subcategories of stationary combustion turbines. Those
subcategories could be delisted if it were demonstrated that they met
the requirements of CAA section 112(c)(9).
The GTA letter includes information on the risks created by
emissions from lean-premix turbines. We are already proposing a
subcategory for lean-premix turbines and in that discussion describe
how these turbines are clearly technologically different from other
types of stationary combustion turbines. While the GTA letter did not
provide sufficient information for us to delist lean-premix turbines at
this time, lean-premix turbines are a subcategory that could be
delisted if GTA or other commenters provide sufficient information for
us to determine that this subcategory satisfies the requirements of CAA
section 112(c)(9).
Natural gas fired turbines are another example of a subcategory
that might be delisted under this approach. We have created
subcategories based on fuel type in other MACT rules and believe that
fuel type could be an appropriate way of subcategorizing stationary
combustion turbines or of creating further subdivisions within the
subcategories contained in the proposed rule. We are not proposing a
subcategory for natural gas fired turbines at this time, although we
could create such a subcategory in the future, if appropriate. While
the information presented in GTA's letter is not sufficient for us to
make this determination at this time, additional information on the
emissions and risks from natural gas fired turbines could lead us to
delist natural gas fired turbines under this approach.
The EPA requests comment on the concept of identifying
technologically-based subcategories that may include only low-risk
facilities within the combustion turbine source category and on the
specific examples presented above.
Another approach to using the authority granted in CAA section
112(c)(9) is presented in the white paper prepared by representatives
of the plywood and composite wood products industry (see docket OAR
2002-0060). The EPA is considering whether it would be possible to
establish a subcategory of facilities within the larger source category
that would meet the risk-based criteria for delisting. Such criteria
would likely include the same requirements as described previously for
the second scenario under the CAA section 112(d)(4) approach, whereby a
facility would be in the low-risk subcategory if its emissions of
threshold pollutants do not result in exposures which exceed the HI
limits and if its emissions of nonthreshold pollutants do not exceed a
cancer risk level of 10-6. The EPA requests comment on what
an appropriate HI limit would be for a determination that a facility be
included in the low-risk subcategory.
Since each facility in such a subcategory would be a low-risk
facility (i.e., if each met these criteria), the subcategory could be
delisted in accordance with CAA section 112(c)(9), thereby limiting the
costs and impacts of the proposed MACT rule to only those facilities
that do not qualify for subcategorization and delisting.
Facilities seeking to be included in the delisted subcategory would
be responsible for providing all data required to determine whether
they are eligible for inclusion. Facilities that could not demonstrate
that they are eligible to be included in the low-risk subcategory would
be subject to MACT and possible future residual risk standards. The EPA
solicits comment on

[[Page 1909]]

implementing a risk-based approach for establishing subcategories of
stationary combustion turbines.
Since each facility in such a subcategory would be a low-risk
facility (i.e., if each met these criteria), the subcategory could be
delisted in accordance with CAA section 112(c)(9), thereby limiting the
costs and impacts of the proposed MACT rule to only those facilities
that do not qualify for subcategorization and delisting.
Establishing that a facility qualifies for the low-risk subcategory
under CAA section 112(c)(9) will necessarily involve combining
estimates of pollutant emissions with air dispersion modeling to
predict exposures. The EPA envisions that we would employ the same
tiered analysis described earlier in the CAA section 112 (d)(4)
discussion for these determinations.
One concern that EPA has with respect to the CAA section 112(c)(9)
approach is the effect that it could have on the MACT floors. If many
of the facilities in the low-risk subcategory are well-controlled, that
could make the MACT floor less stringent for the remaining facilities.
One approach that has been suggested to mitigate this effect would be
to establish the MACT floor now based on controls in place for the
entire category and to allow facilities to become part of the low-risk
subcategory in the future, after the MACT standards are established.
This would allow low-risk facilities to use the CAA section 112(c)(9)
exemption without affecting the MACT floor calculation. The EPA
requests comment on this suggested approach.
If a CAA section 112(c)(9) approach were adopted, the requirements
of the rule as proposed would not apply to any source that demonstrates
that it belongs in a subcategory which has been delisted under CAA
section 112(c)(9).

C. Limited Use Subcategory

We are soliciting comments on creating a subcategory of limited use
stationary combustion turbines with capacity utilization of 10 percent
or less (876 or fewer hours of annual operation). Units in this
subcategory would include combustion turbines used for electric power
peak shaving that are called upon to operate fewer than 876 hours per
year. These units operate only during peak energy use periods,
typically in the summer months. We believe that these infrequently
operated units typically operate 10 percent of the year or less. While
these are potential sources of emissions, and it is appropriate for EPA
to address them in the proposed rule, the Agency believes that their
use and operation are different compared to typical combustion
turbines. We believe that it may be appropriate for such limited use
units to have their own subcategory. Therefore, we are soliciting
comment on subcategorizing combustion turbines having a capacity
utilization of less than 10 percent.
We are interested in comments on creating a subcategory for limited
use peak shaving (less than 10 percent capacity utilization) combustion
turbines. We are interested in comments on the validity and
appropriateness under the CAA for a subcategory for limited use peak
shaving combustion turbines, data on the levels of control currently
achieved by such combustion turbines, and any technical limitations
that might make it impossible to achieve control of emissions from
limited use peak shaving combustion turbines.

VI. Administrative Requirements

A. Executive Order 12866, Regulatory Planning 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 proposed 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. 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 proposed rule does not have federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132.
We are required by section 112 of the CAA, 42 U.S.C. Sec. 7412, to
establish the standards in the proposed rule. The proposed rule
primarily affects private industry, and does not impose significant
economic costs on State or local governments. The proposed rule does
not include an express provision preempting State or local regulations.
Thus, the requirements of section 6 of the Executive Order do not apply
to the proposed rule.
Although section 6 of Executive Order 13132 does not apply to the
proposed rule, we consulted with representatives of State and local
governments to enable them to provide meaningful and timely input into
the development of the proposed rule. This consultation took place
during the ICCR FACA committee meetings where members representing
State and local governments participated in developing recommendations
for EPA's combustion-related rulemakings, including the proposed rule.
The concerns raised by representatives of State and local governments
were considered during the development of the proposed rule.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on the proposed rule
from State and local officials.

C. Executive Order 13175, Consultation and Coordination with Indian
Tribal Governments

Executive Order 13175 (59 FR 22951, November 6, 2000), requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by tribal officials in the development of regulatory policies
that have tribal

[[Page 1910]]

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 proposed 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. We
do not know of any stationary combustion turbines owned or operated by
Indian tribal governments. However, if there are any, the effect of
these rules on communities of tribal governments would not be unique or
disproportionate to the effect on other communities. Thus, Executive
Order 13175 does not apply to the proposed rule.

D. 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 proposed rule is not
subject to Executive Order 13045 because it is based on technology
performance and not on health or safety risks.

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

Executive Order 13211 (66 FR 28355, May 22, 2001), provides that
agencies shall prepare and submit to the Administrator of the Office of
Information and Regulatory Affairs, Office of Management and Budget, a
Statement of Energy Effects for certain actions identified as
``significant energy actions.'' Section 4(b) of Executive Order 13211
defines ``significant energy actions'' as ``any action by an agency
(normally published in the Federal Register) that promulgates or is
expected to lead to the promulgation of a final rule or regulation,
including notices of inquiry, advance notices of proposed rulemaking,
and notices of proposed rulemaking: (1) (i) That is a significant
regulatory action under Executive Order 12866 or any successor order,
and (ii) is likely to have a significant adverse effect on the supply,
distribution, or use of energy; or (2) that is designated by the
Administrator of the Office of Information and Regulatory Affairs as a
significant energy action.'' The proposed rule is a significant
regulatory action within the meaning of Executive Order 12866. We have,
therefore, prepared a Statement of Energy Effects for this action as
follows.
The increase in petroleum product output, which includes increases
in fuel production, is estimated at 0.003 percent, or about 475 barrels
per day based on 2000 U.S. fuel production nationwide. The reduction in
coal production is estimated at 0.006 percent, or about 700,000 short
tons per year based on 2000 U.S. coal production nationwide. The
reduction in electricity output is estimated at 0.02 percent, or about
4.9 billion kilowatt-hours per year based on 2000 U.S. electricity
production nationwide. Production of natural gas is expected to
increase by 3.0 million cubic feet (ft\3\) 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 0.18 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 proposed 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 proposed rule when implemented will
not have a significant adverse effect on the supply, distribution, or
use of energy.

F. 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.
We have determined that the proposed rule contains a Federal
mandate that will not result in expenditures of $100 million or more

[[Page 1911]]

for State, local, and tribal governments, in the aggregate, or the
private sector in any 1 year. Accordingly, we have not prepared a
written statement under section 202 of the UMRA.
1. Statutory Authority
As discussed in previously in this preamble, the statutory
authority for the proposed rulemaking is section 112 of the CAA. Title
III of the CAA was enacted to reduce nationwide air toxic emissions.
Section 112(b) of the CAA lists the 188 chemicals, compounds, or groups
of chemicals deemed by Congress to be HAP. These toxic air pollutants
are to be regulated by NESHAP.
Section 112(d) of the CAA directs us to develop NESHAP which
require existing and new major sources to control emissions of HAP
using MACT. The NESHAP apply to all stationary combustion turbines
located at major sources of HAP emissions, however, only new or
reconstructed stationary combustion turbines have substantive
regulatory requirements.
In compliance with section 205(a) we identified and considered a
reasonable number of regulatory alternatives. Additional information on
the costs and environmental impacts of the regulatory alternatives is
presented in the ``Stationary Combustion Turbines Control Options Cost
Information Summary'' in the docket.
The regulatory alternative upon which the proposed rule is based
represents the MACT floor for stationary combustion turbines and, as a
result, it is the least costly and least burdensome alternative. In
addition, we have conducted an economic impact analysis of today's
proposed rule that includes the impacts on State and local government
entities in order to provide information on the effects of the proposed
rule on such entities. The analysis is available in the docket for the
proposed rule.
2. Consultation With Government Officials
The Unfunded Mandates Act requires that we describe the extent of
the Agency's prior consultation with affected State, local, and tribal
officials, summarize the officials' comments or concerns, and summarize
our response to those comments or concerns.
In addition, section 203 of the UMRA requires that we develop a
plan for informing and advising small governments that may be
significantly or uniquely impacted by a proposal. Although the proposed
rule does not significantly affect any State, local, or tribal
governments, we have consulted with State and local air pollution
control officials. We also have held meetings on the proposed 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 proposed rule contains no
regulatory requirements that might significantly or uniquely affect
small governments. Therefore, today's proposed rule is not subject to
the requirements of section 203 of the UMRA.

G. Regulatory Flexibility Act (RFA), as Amended by the Small Business
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et
seq.

The RFA generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment
rulemaking requirements under the Administrative Procedure Act or any
other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small organizations, and small
governmental jurisdictions.
For purposes of assessing the impacts of today's proposed rule on
small entities, small entity is defined as: (1) A small business whose
parent company has fewer than 100 or 1,000 employees, depending on size
definition for the affected North American Industry Classification
System (NAICS) code, or fewer than 4 billion kW-hr per year of
electricity usage; (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 proposed rule, and
the small 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 proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. This
certification is based upon (1) examining the impacts to small entities
based on the existing combustion turbines inventory, and presuming that
the existing mix of combustion turbines among industries is a good
approximation of the mix of turbines that will be installed and
affected by the proposed rule up to 2005, and (2) considering
influences on the decision by small entities to install new turbines.
We have determined, based on the existing combustion turbines
inventory, that 29 small entities out of 300 in the industries impacted
by the proposed rule may be affected. None of these small entities will
incur control costs associated with the proposed 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 only
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 only 0.07 percent of
sales. In addition, the proposed 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 rule as a result of the very slight increase in market prices.
Thus, we conclude that the proposed rule will not have a significant
impact on a substantial number of small entities. It should be noted
that it is likely that the ongoing deregulation of the electric power
industry across the nation should minimize the proposed rule's impacts
on small entities. Increased competition in the electric power industry
is forecasted to decrease the market price for wholesale electric
power. 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 proposed rule will not have a significant economic
impact on a substantial number of small entities, EPA nonetheless has
tried to reduce the impact of the rule on small entities. In the
proposed 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. In addition, as
mentioned earlier in the preamble, new turbines with capacities under
1.0 MW are not covered by the

[[Page 1912]]

proposed rule. This provision should reduce the level of small entity
impacts. We continue to be interested in the potential impacts of the
proposed rule on small entities and welcome comments on issues related
to such impacts.

H. Paperwork Reduction Act

The information collection requirements in the proposed rule will
be submitted for approval to the Office of Management and Budget under
the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. An Information
Collection Request (ICR) document has been prepared (ICR No. 1967.01)
and a copy may be obtained from Susan Auby by mail at the Collection
Strategies Division, U.S. Environmental Protection Agency (2822), 1200
Pennsylvania Avenue NW, Washington, DC 20460, by e-mail at
auby.susan@epa.gov, or by calling (202) 566-1672. A copy may also be
downloaded off the internet at http://www.epa.gov/icr.
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 proposed rule would require maintenance inspections of the
control devices but would 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 standards) is estimated to be 8,458 labor hours per year at a total
annual cost of $2.4 million. 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 $515,262, with operation and
maintenance costs of $21,047 per year.
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 our
regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
Comments are requested on the Agency's need for this information,
the accuracy of the provided burden estimates, and any suggested
methods for minimizing respondent burden, including through the use of
automated collection techniques. Send comments on the ICR to the
Director, Collection Strategies Division, U.S. Environmental Protection
Agency (2822), 1200 Pennsylvania Ave., NW, Washington, DC 20460; and to
the Office of Information and Regulatory Affairs, Office of Management
and Budget, 725 17th St., NW, Washington, DC 20503, marked Attention:
Desk Officer for EPA. Include the ICR number in any correspondence.
Since OMB is required to make a decision concerning the ICR between
30 and 60 days after January 14, 2003, a comment to OMB is best assured
of having its full effect if OMB receives it by February 13, 2003. The
final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.

I. National Technology Transfer and Advancement Act

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 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 us 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 proposed rulemaking involves technical standards. We propose in
the rule to use EPA Methods 1, 1A, 3A, 3B, 4 of 40 CFR part 60,
appendix A; Method 320 of 40 CFR part 63, appendix A; Method 323 of 40
CFR part 63, appendix A; Performance Specification (PS) 3, PS 4A of 40
CFR part 60, appendix B; EPA SW-846 Method 0011; and ARB Method 430,
California Environmental Protection Agency, Air Resources Board, 2020 L
Street, Sacramento, CA 95812. Consistent with the NTTAA, we conducted
searches to identify voluntary consensus standards in addition to these
EPA methods. No applicable voluntary consensus standards were
identified for EPA Methods 1A, 3B of 40 CFR part 60, appendix A; PS 3,
PS 4 of 40 CFR part 60, appendix B; and ARB Method 430, California
Environmental Protection Agency, Air Resources Board, 2020 L Street,
Sacramento, CA 95812. The search and review results have been
documented and are placed in the docket for the proposed rule.
This search for emission measurement procedures identified nine
voluntary consensus standards. We determined that six of these nine
standards were impractical alternatives to EPA test methods for the
purposes of the proposed rulemaking. Therefore, we do not propose to
adopt these standards today. The reasons for this determination for the
six methods are discussed below.
Two of the six voluntary consensus standards are impractical
alternatives to EPA test methods for the purposes of the proposed
rulemaking because they are too general, too broad, or not sufficiently
detailed to assure compliance with EPA regulatory requirements: ASTM
E337-84 (Reapproved 1996), ``Standard Test Method for Measuring
Humidity with a Psychrometer (the Measurement of Wet- and Dry-Bulb
Temperatures),'' for EPA Method 4; and CAN/CSA Z223.2-M86(1986),
``Method for the Continuous Measurement of Oxygen, Carbon Dioxide,
Carbon Monoxide, Sulphur Dioxide, and Oxides of Nitrogen in Enclosed
Combustion Flue Gas Streams,'' for EPA Method 3A of 40 CFR part 60,
appendix A.
Four of the six voluntary consensus standards are impractical
alternatives to EPA test methods for the purposes of the proposed
rulemaking because they

[[Page 1913]]

lacked sufficient quality assurance and quality control requirements
necessary for EPA compliance assurance requirements: ASTM D3154-91,
``Standard Method for Average Velocity in a Duct (Pitot Tube Method),''
for EPA Methods 1, 2, 2C, 3, 3B, and 4 of 40 CFR part 60, appendix A;
ASTM D5835-95, ``Standard Practice for Sampling Stationary Source
Emissions for Automated Determination of Gas Concentration,'' for EPA
Method 3A of 40 part 60, appendix A; ISO 10396:1993, ``Stationary
Source Emissions: Sampling for the Automated Determination of Gas
Concentrations,'' for EPA Method 3A of 40 CFR part 60, appendix A; and
ISO 9096:1992, ``Determination of Concentration and Mass Flow Rate of
Particulate Matter in Gas Carrying Ducts--Manual Gravimetric Method,''
for EPA Method 5 of 40 CFR part 60, appendix A.
The following three of the nine voluntary consensus standards
identified in this search were not available at the time the review was
conducted for the purposes of the proposed rulemaking because they are
under development by a voluntary consensus body: ASME/BSR MFC 13M,
``Flow Measurement by Velocity Traverse,'' for EPA Method 1 (and
possibly 2) of 40 CFR part 60, appendix A; ISO/DIS 12039, ``Stationary
Source Emissions--Determination of Carbon Monoxide, Carbon Dioxide, and
Oxygen--Automated Methods,'' for EPA Method 3A of 40 CFR part 60,
appendix A; and ASTM D6348-98, ``Determination of Gaseous Compounds by
Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy,''
for EPA Method 320 of 40 CFR part 63, appendix A. While we are not
proposing to include these three voluntary consensus standards in
today's proposal, we will consider the standards when final.
For the voluntary consensus standard, ASTM D6348-98, Determination
of Gaseous Compounds by Extractive Direct Interface Fourier Transform
(FTIR) Spectroscopy, we have submitted comments to ASTM regarding EPA's
technical evaluation of ASTM D6348-98. Currently, the ASTM Subcommittee
D22-03 is undertaking a revision of the ASTM standard in part to
address EPA's comments. Upon successful ASTM balloting and
demonstration of technical equivalency with the EPA's FTIR methods, the
revised ASTM standard could be incorporated by reference into the
proposed rule at a later date.
We are taking comment on the compliance demonstration requirements
in the proposed rulemaking and specifically invite the public to
identify potentially-applicable voluntary consensus standards.
Commenters should also explain why the proposed rule should adopt these
voluntary consensus standards in lieu of or in addition to EPA's
standards. Emission test methods and performance specifications
submitted for evaluation should be accompanied with a basis for the
recommendation, including method validation data and the procedure used
to validate the candidate method (if a method other than Method 301, 40
CFR part 63, Appendix A, was used).
Tables 3 and 5 of proposed subpart YYYY list the EPA testing
methods and performance standards included in the proposed rule. Under
Sec. 63.8 of 40 CFR part 63, subpart A, a source may apply to EPA for
permission to use alternative monitoring in place of any of the EPA
testing methods.

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: November 26, 2002.
Christine Todd Whitman,
Administrator.

For the reasons set out in the preamble, title 40, chapter I, part
63 of the Code of the Federal Regulations is proposed to be amended as
follows:

PART 63--[AMENDED]

1. The authority citation for part 63 continues to read as follows:

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

2. Part 63 is proposed to be amended by adding subpart YYYY to read
as follows:
Subpart YYYY--National Emission Standards for Hazardous Air Pollutants
for Stationary Combustion Turbines

What This Subpart Covers

Sec.
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 Sea 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
Emission Limitations
Table 6 to Subpart YYYY of Part 63.--Continuous Compliance with
Operating Limitations
Table 7 to Subpart YYYY of Part 63.-- Requirements for Reports
Table 8 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.

[[Page 1914]]

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) A stationary combustion turbine is one that 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.
(b) 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 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 turbine. A stationary combustion turbine is new
if you commenced construction of the stationary combustion turbine
after January 14, 2003.
(3) Reconstructed stationary 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) Exceptions. (1) A new or reconstructed stationary combustion
turbine located at a major source or an existing lean premix stationary
combustion turbine located at a major source which meets any 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;
(ii) The stationary combustion turbine is a limited use stationary
combustion turbine; or
(iii) The stationary combustion turbine burns landfill gas or
digester gas as the primary fuel.
(2) 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.
(3) Existing diffusion flame stationary combustion turbines do not
have to meet the requirements of this subpart and of subpart A of this
part.
(4) 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.

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.

Sec. 63.6095 When do I have to comply with this subpart?

(a) Affected sources. (1) If you start up your new or reconstructed
stationary combustion turbine before [DATE THE FINAL RULE IS PUBLISHED
IN THE FEDERAL REGISTER], you must comply with the emission limitations
and operating limitations in this subpart no later than [DATE THE FINAL
RULE IS PUBLISHED IN THE FEDERAL REGISTER].
(2) If you start up your new or reconstructed stationary combustion
turbine after [DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL
REGISTER], you must comply with the emission limitations and operating
limitations in this subpart upon startup of your affected source.
(3) If you have an existing stationary combustion turbine, you must
comply with the emission limitations and operating limitations in this
subpart no later than 3 years after [DATE THE FINAL RULE IS PUBLISHED
IN THE FEDERAL REGISTER].
(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 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 stationary combustion turbine with a rated peak power
output of 1.0 MW or greater at ISO standard day conditions located at a
major source, which is not:
(a) An emergency stationary combustion turbine;
(b) A stationary combustion turbine burning landfill gas or
digester gas as its primary fuel;
(c) A limited use stationary combustion turbine; or
(d) An existing diffusion flame stationary combustion turbine; 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?

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).

[[Page 1915]]

Sec. 63.6115 When must I conduct subsequent performance tests?

If you are complying with the formaldehyde emission concentration
limitation and your stationary combustion turbine is lean premix, this
section applies to you. If you are not attaining low NO_X
levels, as permitted by an enforcement agency, or if there are not
permit levels and you are not attaining low NO_X levels
characteristic of lean premix combustion (e.g., NO_X levels
guaranteed by the manufacturer), additional performance testing may be
required by the enforcement agency.

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) For demonstrations of initial compliance with the emission
limitation for carbon monoxide (CO) reduction, you must complete the
actions described in paragraphs b(1) and (2) of this section.
(1) Normalize the CO concentrations at the inlet and outlet of the
oxidation catalyst emission control device to a dry basis and to 15
percent oxygen or an equivalent percent carbon dioxide
(CO₂).
(2) Calculate the percent reduction of CO using the following
equation 1 of this section:
[GRAPHIC]
[TIFF OMITTED]
TP14JA03.000

Where:

C_i = CO concentration at inlet of the oxidation catalyst
emission control device
C_o = CO concentration at the outlet of the oxidation
catalyst emission control device
R = percent reduction in CO emissions.

(3) The initial demonstration of compliance consists of the first
4-hour average percent reduction in CO recorded after completion of the
performance evaluation of the CEMS.
(c) 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.
(d) Do not conduct performance tests or compliance evaluations
during periods of startup, shutdown, or malfunction.
(e) If you comply with the emission limit for formaldehyde emission
concentration, you must conduct three separate test runs for each
performance test, and each test run must last at least 1 hour.
(f) If you comply with the emission limitation for formaldehyde
emission concentration and your stationary combustion turbine is not
diffusion flame or lean premix, you must petition the Administrator for
additional operating limitations to be established during the initial
performance test and continuously monitored thereafter, or for approval
of no additional operating limitations. You must not conduct the
initial performance test until after the petition has been approved by
the Administrator.
(g) If you comply with the emission limitation for formaldehyde
emission concentration and your stationary combustion turbine is not
diffusion flame or lean premix and you petition the Administrator for
approval of additional operating limitations, your petition must
include the following information described in paragraphs (g)(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.
(h) If you comply with the emission limitation for formaldehyde
emission concentration and you petition the Administrator for approval
of no additional operating limitations, your petition must include the
information described in paragraphs (h)(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 whether establishing
limitations on the parameters would serve to limit HAP emissions;
(4) For the parameters which could change in such a way as to
increase HAP emissions, a discussion of how you could establish upper
and/or lower values for the parameters which would establish limits on
the parameters in operating limitations;
(5) For the parameters, 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
or unreasonable to adopt the parameters as operating limitations.

Sec. 63.6125 What are my monitor installation, operation, and
maintenance requirements?

(a) If you comply with the emission limitation for CO reduction,
you must install, operate, and maintain a CEMS to monitor CO and either
oxygen or CO₂ at both the inlet and outlet of the oxidation
catalyst emission control device according to the requirements
described in paragraphs (a)(1) through (4) of this section.
(1) You must install, operate, and maintain each CEMS according to
the applicable Performance Specification of 40 CFR part 60, appendix B
(PS-4A).
(2) You must conduct a performance evaluation of each CEMS
according to the requirements in 40 CFR 63.8 and according to the
applicablePerformance Specification of 40 CFR part 60, appendix B.
(3) As specified in Sec. 63.8(c)(4)(ii), each CEMS must complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each consecutive 15-minute period. You must have at
least two data points, each representing a different 15-minute period
within the same hour to have a valid hour of data.
(4) Continuous emission monitoring system data must be reduced as
specified in Sec. 63.8(g)(2) and recorded in parts per million (ppm)
CO at 15 percent oxygen or equivalent CO₂ concentration.
(b) If you have monitors that are subject to paragraph (a) of this
section, you must properly maintain and operate the monitors
continuously according to the requirements described in paragraphs
(b)(1) and (2) of this section.

[[Page 1916]]

(1) Proper maintenance. You must maintain the monitoring equipment
at all times that the turbine is operating, including but not limited
to, maintaining necessary parts for routine repairs of the monitoring
equipment.
(2) Continued operation. You must conduct all monitoring in
continuous operation at all times that the combustion turbine is
operating, except for, as applicable, monitoring malfunctions,
associated repairs, and required quality assurance or control
activities (including, as applicable, calibration checks and required
zero and span adjustments). Data recorded during monitoring
malfunctions, associated repairs, out-of-control periods, and required
quality assurance or control activities shall not be used for purposes
of calculating data averages. You must use all of the data collected
from all other periods in assessing compliance. A monitoring
malfunction is any sudden, infrequent, not reasonably preventable
failure of the monitoring equipment to provide valid data. Monitoring
failures that are caused in part by poor maintenance or careless
operation are not malfunctions. Any period for which the monitoring
system is out-of-control and data are not available for required
calculations constitutes a deviation from the monitoring requirements.

Sec. 63.6130 How do I demonstrate initial compliance with the
emission 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).

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 monitoring in
continuous operation 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 and Table 6 of this
subpart.
(b) You must report each instance in which you did not meet each
emission limitation or operating limitation. You must also report each
instance in which you did not meet the requirements in Table 8 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.

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 (6), 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
combustion turbine before [DATE THE FINAL RULE IS PUBLISHED IN THE
FEDERAL REGISTER], you must submit an Initial Notification not later
than 120 calendar days after [DATE THE FINAL RULE IS PUBLISHED IN THE
FEDERAL REGISTER].
(c) As specified in Sec. 63.9(b), if you start up your new or
reconstructed stationary combustion turbine on or after [DATE THE FINAL
RULE IS PUBLISHED IN THE FEDERAL REGISTER], 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 requirements of this subpart, in
accordance with Sec. 63.6090(b), your notification should 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 requirements and 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 either the emission
limitation for CO reduction or the emission limitation for formaldehyde
emission concentration, you must submit a Notification of Compliance
Status according to Sec. 63.9(h)(2)(ii).
(1) For each initial compliance demonstration with the emission
limitation for CO reduction, you must submit the Notification of
Compliance Status before the close of business on the 30th calendar day
following the completion of the initial compliance demonstration.
(2) For each performance test required to demonstrate compliance
with the emission limitation for formaldehyde emission concentration,
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) Any one who owns or operates a new or reconstructed stationary
combustion turbine which must meet the emission limitation for CO
reduction must submit a semiannual compliance report according to Table
7 of this subpart by the date specified in paragraphs (a)(1) through
(5) of this section unless the Administrator has approved a different
schedule, according to the information described in paragraphs (a)(1)
through (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.

[[Page 1917]]

(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 new or reconstructed 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 semiannual 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 (a)(1)
through (4) of this section.
(b) The semiannual compliance report must contain the information
described in paragraphs (b)(1) through (4) of this section.
(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) If there is no deviation from any emission limitation that
applies to you, a statement that there was no deviation from the
emission limitations during the reporting period and that no CEMS was
inoperative, inactive, malfunctioning, out of control, repaired, or
adjusted.
(c) For each deviation from an emission limitation that occurs
where you are not using a CEMS to comply with the emission limitations
in this subpart, the compliance report must contain the information in
paragraphs (b)(1) through (3) of this section and the information
contained in paragraphs (c)(1) through (3) of this section.
(1) The total operating time of each new or reconstructed
combustion turbine during the reporting period.
(2) Information on the number, duration, and cause of deviations
(including unknown cause, if applicable), as applicable, and the
corrective action taken.
(3) 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).
(d) For each deviation from an emission limitation occurring where
you are using a CEMS to comply with an emission limitation, you must
include the information in paragraphs (c)(1) through (3) of this
section and the information included in paragraphs (d)(1) through (11)
of this section.
(1) The date and time that each deviation started and stopped.
(2) The date and time that each CEMS was inoperative except for
zero (low-level) and high-level checks.
(3) The date and time that each CEMS was out-of-control including
the information in Sec. 63.8(c)(8).
(4) The date and time that each deviation started and stopped, and
whether each deviation occurred during a period of startup, shutdown or
malfunction or during another period.
(5) A summary of the total duration of the deviation during the
reporting period (recorded in 4-hour periods), and the total duration
as a percent of the total operating time during that reporting period.
(6) A breakdown of the total duration of the deviations during the
reporting period into those that are due to control equipment problems,
process problems, other known causes, and other unknown causes.
(7) A summary of the total duration of CEMS downtime during the
reporting period (reported in 4-hour periods), and the total duration
of CEMS downtime as a percent of the total turbine operating time
during that reporting period.
(8) A breakdown of the total duration of CEMS downtime during the
reporting period into periods that are due to monitoring equipment
malfunctions, non-monitoring equipment malfunctions, quality assurance/
quality control calibrations, other known causes and other unknown
causes.
(9) The monitoring equipment manufacturer(s) and model number(s) of
each monitor.
(10) The date of the latest CEMS certification or audit.
(11) A description of any changes in CEMS or controls since the
last reporting period.

Sec. 63.6155 What records must I keep?

(a) You must keep the records as described in paragraphs (a)(1)
through (5) of this section.
(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) For each CEMS, you must keep the records as described in
paragraphs (b)(1) through (3) of this section.
(1) Records described in Sec. 63.10(b)(2)(vi) through (xi).
(2) Previous (i.e., superceded) versions of the performance
evaluation plan as required in Sec. 63.8(d)(3).
(3) Request for alternatives to the relative accuracy test for CEMS
as required in Sec. 63.8(f)(6)(i), if applicable.
(c) You must keep the records required in Tables 5 and 6 of this
subpart to show continuous compliance with each emission limitation and
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 8 of this subpart shows which parts of the General Provisions
in Sec. 63.1 through 13 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.

[[Page 1918]]

(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.

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 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.
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; or
(3) Fails to meet any emission limitation or operating limitation
in this subpart during malfunction, regardless or whether or not such
failure is permitted by this subpart.
Diffusion flame stationary combustion turbine means any 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
formed through the anaerobic decomposition of organic waste materials
and composed principally of methane and CO₂.
Emergency stationary combustion turbine means any stationary
combustion turbine that operates as a mechanical or electrical power
source when the primary source of power is interrupted by an emergency
situation. Examples include stationary combustion turbines used to
produce power for critical networks or equipment 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.
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 (15 [deg]C),
60 percent relative humidity and 101.3 kilopascals pressure.
Landfill gas means a gaseous by-product of the land application of
municipal refuse formed through the anaerobic decomposition of waste
materials and composed principally of methane and CO₂.
Lean premix stationary combustion turbine means any stationary
combustion turbine where the air and fuel are thoroughly mixed to form
a lean mixture before delivery to the combustor.
Limited use stationary combustion turbine means any stationary
combustion turbine which is operated 50 hours or less per calendar
year.
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 except
when they are on the same surface site;
(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; and
(3) For production field facilities, only HAP emissions from glycol
dehydration units, storage tanks with flash emissions potential,
combustion turbines and reciprocating internal combustion engines shall
be aggregated for a major source determination.
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.
Failures that are caused in part by poor maintenance or careless
operation are not malfunctions.
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,

[[Page 1919]]

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 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.
Production field facility means those oil and gas production
facilities located prior to the point of custody transfer.
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.
Simple cycle stationary combustion turbine means any stationary
combustion turbine that does not recover heat from the stationary
combustion turbine exhaust gases.
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. Sec. 63.6100 and 63.6140, you must comply with
the following emission limitations:

Table 1 to Subpart YYYY of Part 63.--Emission Limitations
------------------------------------------------------------------------
You must meet one of the
For . . . following emission limitations
. . .
------------------------------------------------------------------------
1. each stationary combustion turbine a. achieve a reduction in CO of
described in Sec. 63.6100. 95 percent or greater,
measured before and after an
oxidation catalyst emission
control device is installed to
treat all of the stationary
combustion turbine exhaust
gases, if you install an
oxidation catalyst emission
control device or
b. limit the concentration of
formaldehyde to 43 ppbvd or
less at 15 percent O₂, if you
do not install an oxidation
catalyst emission control
device.
------------------------------------------------------------------------

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 Meet no operating
complying with the emission limitation limitations.
for CO reduction.
-------------------------------------------
2. Each stationary combustion turbine Meet no operating
complying with the emission limitation limitations.
for formaldehyde emission concentration
that is diffusion flame or lean premix.
-------------------------------------------
3. Each stationary combustion turbine You must comply with any
complying with the emission limitation additional operating
for formaldehyde emission concentration limitations approved by the
that is not diffusion flame or lean Administrator.
premix.
------------------------------------------------------------------------

As stated in Sec. 63.6120, you must comply with the following
requirements for performance tests and initial compliance
demonstrations:

Table 3 of Subpart YYYY of Part 63.--Requirements for Performance Tests and Initial Compliance Demonstrations
----------------------------------------------------------------------------------------------------------------
According to the
For each stationary combustion You must . . Using . . . following requirements
turbine complying with . . . . . .
----------------------------------------------------------------------------------------------------------------
1. The emission limitation for CO Demonstrate a reduction A CEMS for CO and This demonstration is
reduction. in CO of 95 percent or either O₂ or CO₂ to conducted immediately
more. monitor at both the following a successful
inlet and outlet of performance evaluation
the oxidation catalyst of the CEMS as
emission control required in Sec.
device. 63.6125(a). The
demonstration consists
of the first 4-hour
average of
measurements. The
reduction in CO is
calculated using the
equation in Sec.
63.6120 and must be
normalized to 15
percent O₂ or
equivalent percent
CO₂.
--------------------------------------

[[Page 1920]]

2. The emission limitation for a. Demonstrate i. Test Method 320 of (1) Formaldehyde
formaldehyde emission concentration. formaldehyde emissions 40 CFR part 63, concentration must be
are 43 ppbvd or less appendix A; or EPA SW- corrected to 15
by a performance test 846 Method 0011; or percent O₂, dry basis.
and. California Results of this test
Environmental consist of the average
Protection Agency, Air of the three 1 hour
Resources Board, runs.
Method 430*
formaldehyde and
acetaldehyde in
emissions from
stationary sources,
adopted Sept 12, 1989,
amended December 13,
1991 (ARB Method
430)*; or if your
affected source fires
natural gas, Test
Method 323 of 40 CFR
part 63, appendix A;
or other methods
approved by the
Administrator.
b. Select the sampling i. Method 1 or 1A of 40 (1) If using an air
port location and the CFR part 60, appendix pollution control
number of traverse A Sec. 63.7(d)(1)(i). device, the sampling
points and. site must be located
at the outlet of the
air pollution control
device.
c. Determine the O₂ i. Method 3A or 3B of (1) Measurements to
concentration at the 40 CFR part 60, determine O₂
sampling port location. appendix A. concentration must be
made at the same time
as the performance
test.
----------------------------------------------------------------------------------------------------------------
\*\ You may obtain a copy of ARB Method 430 from the California Environmental Protection Agency, Air Resources
Board, 2020 L Street, Sacramento, CA 95812, or you may download a copy of ARB Method 430 from ARB's web site
(http://www.arb.ca.gov/testmeth/vol3/vol3.htm).

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
For the . . . initial compliance if . . .
------------------------------------------------------------------------
1. Emission limitation for CO reduction... The average reduction of CO
emissions is at least 95
percent, dry basis.
-------------------------------------------
2. Emission limitation for formaldehyde... The average formaldehyde
concentration is 43 ppbvd
or less at 15 percent O₂.
------------------------------------------------------------------------

As stated in Sec. Sec. 63.6135 and 63.6140, you must comply with
the following requirements to demonstrate continuing compliance with
emissions limitations:

Table 5 of Subpart YYYY of Part 63.--Continuous Compliance with Emission
Limitations
------------------------------------------------------------------------
You must demonstrate continous compliance
For the . . . by . . .
------------------------------------------------------------------------
1. Emission limitation for CO a. Collecting the CEMS data according to
reduction. Sec. 63.6125(a), reducing the
measurements to 1-hour averages,
calculating the percent reduction in CO
emissions according to Sec. 63.6120;
and
b. Demonstrating a reduction in CO of 95
percent or more over each 4-hour
averaging period; and
c. Applying 40 CFR part 60 appendix F,
procedure 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 6 of Subpart YYYY of Part 63.--Continuous Compliance with
Operating Limitations
------------------------------------------------------------------------
You must demonstrate
For the emission limitation For the operating continuous
. . . limitation . . . compliance by . . .

------------------------------------------------------------------------
For formaldehyde............ To comply with Collect the data
operating according to Sec.
limitations 63.6120(g) and
approved by the maintain the
Administrator. operating
parameters within
the operating
limits.
------------------------------------------------------------------------

As stated in Sec. Sec. 63.6145 and 63.6150, you must comply with
the following requirements for reports:

[[Page 1921]]

Table 7 of Subpart YYYY of Part 63.--Requirements for Reports
----------------------------------------------------------------------------------------------------------------
If you own or operate a stationary
combustion turbine which must comply
with the CO emission reduction
limitation, you must submit a . . .
----------------------------------------------------------------------------------------------------------------
Semiannual compliance report............ If there is no deviation from any emission Semiannually, according to
limitation or operating limitation, a the requirements in
statement that you have had no deviation $63,6150.
from the emission limitation or operating
limitation during the reporting period
and that no CEMS or CPMS was inoperative,
inactive, out-of-control, repaired, or
adjusted. If you had a deviation from any
emission limitation or operating
limitation during the reporting period,
the report must contain the information
in Sec. 63.6150(d) or (e), as
applicable.
----------------------------------------------------------------------------------------------------------------

You must comply with the applicable General Provisions
requirements:

Table 8 of Subpart YYYY of Part 63.--Applicability of General Provisions to Subpart YYYY
----------------------------------------------------------------------------------------------------------------
Applies to subpart
Citation Subject YYYY Explanation
----------------------------------------------------------------------------------------------------------------
Sec. 63.1(a)(1)................. General applicability of Yes.................. Additional terms defined
the General Provisions. in Sec. 63.6175.
-----------------------------------
Sec. 63.1(a)(2)-(4)............. Yes..................
-----------------------------------
Sec. 63.1(a)(5)................. [Reserved].
-----------------------------------
Sec. 63.1(a)(6)-(7)............. Contact for source Yes.
category information;
extension of compliance
through early reduction.
-----------------------------------
Sec. 63.1(a)(8)................. .......................... No................... Refers to State programs.
-----------------------------------
Sec. 63.1(a)(9)................. [Reserved].
-----------------------------------
Sec. 63.1(a)(10)-(14)........... .......................... Yes..................
-----------------------------------
Sec. 63.1(b)(1)................. Initial applicability..... Yes.................. Subpart YYYY clarifies
applicability at Sec.
63.6085.
-----------------------------------
Sec. 63.1(b)(2)................. Title V operating permit- Yes.................. All major affected
reference to part 70. sources are required to
obtain a title V permit.
-----------------------------------
Sec. 63.1(b)(3)................. Record of applicability Yes.
determination.
-----------------------------------
Sec. 63.1(c)(1)................. Applicability after Yes.................. Subpart YYYY clarifies
standards are set. the applicability of
each paragraph of
subpart A to sources
subject to subpart YYYY.
-----------------------------------
Sec. 63.1(c)(2)................. Title V permit requirement No................... Area sources are not
for sources. subject to area subpart
YYYY.
-----------------------------------
Sec. 63.1(c)(3)................. [Reserved].
-----------------------------------
Sec. 63.1(c)(4)................. Extension of compliance Yes.
for existing sources.
-----------------------------------
Sec. 63.1(c)(5)................. Notification requirements Yes
for an area source
becoming a major source.
-----------------------------------
Sec. 63.1(d).................... [Reserved].
-----------------------------------
Sec. 63.1(e).................... Applicability of permit Yes.
program before a relevant
standard has been set.
-----------------------------------
Sec. 63.2....................... Definitions............... Yes.................. Additional terms defined
in Sec. 63.6175.
-----------------------------------
Sec. 63.3....................... Units and abbreviations... Yes.
-----------------------------------
Sec. 63.4....................... Prohibited activities..... Yes.
-----------------------------------
Sec. 63.5(a).................... Construction and Yes.
reconstruction
applicability.
-----------------------------------

[[Page 1922]]

Sec. 63.5(b)(1)................. Requirements upon Yes.
construction or
reconstruction.
-----------------------------------
Sec. 63.5(b)(2)................. [Reserved].
-----------------------------------
Sec. 63.5(b)(3)................. Approval of construction.. Yes.
-----------------------------------
Sec. 63.5(b)(4)................. Notification of Yes.
construction.
-----------------------------------
Sec. 63.5(b)(5)................. Compliance................ Yes.
-----------------------------------
Sec. 63.5(b)(6)................. Addition of equipment..... Yes.
-----------------------------------
Sec. 63.5(c).................... [Reserved].
-----------------------------------
Sec. 63.5(d).................... Application for Yes.
construction
reconstruction.
-----------------------------------
Sec. 63.5(e).................... Approval of construction Yes.
or reconstruction.
-----------------------------------
Sec. 63.5(f).................... Approval of construction Yes.
or reconstruction based
on prior State review.
-----------------------------------
Sec. 63.6(a).................... Applicability............. Yes.
-----------------------------------
Sec. 63.6(b)(1)-(2)............. Compliance dates for new Yes.
and reconstructed sources.
-----------------------------------
Sec. 63.6(b)(3)................. Compliance dates for No................... Compliance is required by
sources constructed or startup or effective
reconstructed before date.
effective date.
-----------------------------------
Sec. 63.6(b)(4)................. Compliance dates for Yes.
sources also subject to
Sec. 112(f) standards.
-----------------------------------
Sec. 63.6(b)(5)................. Notification.............. Yes.
-----------------------------------
Sec. 63.6(b)(6)................. [Reserved].
-----------------------------------
Sec. 63.6(b)(7)................. Compliance dates for new Yes.
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)-(2)............. Operation and maintenance. Yes.................. Except that you are not
required to have a
startup, shutdown, and
malfunction plan (SSMP).
-----------------------------------
Sec. 63.6(e)(3)................. SSMP...................... No.
-----------------------------------
Sec. 63.6(f)(1)................. Applicability of standards Yes.
except during startup,
shutdown, or malfunction
(SSM).
-----------------------------------
Sec. 63.6(f)(2)................. Methods for determining Yes.
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 compliance Yes.
exemption.
-----------------------------------

[[Page 1923]]

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 conducting Yes.
performance tests.
-----------------------------------
Sec. 63.7(e)(2)................. Conduct of performance Yes.................. Subpart YYYY specifies
tests and reduction of test methods at Sec.
data. 63.6120.
-----------------------------------
Sec. 63.7(e)(3)................. Test run duration......... Yes.
-----------------------------------
Sec. 63.7(e)(4)................. Administrator may require Yes.
other testing under
section 114 of the CAA.
-----------------------------------
Sec. 63.7(f).................... Alternative test method Yes.
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 requirements. specific requirements
for monitoring at Sec.
63.6125.
-----------------------------------
Sec. 63.8(a)(2)................. Performance specifications Yes.
-----------------------------------
Sec. 63.8(a)(3)................. [Reserved].
-----------------------------------
Sec. 63.8(a)(4)................. Monitoring with flares.... No.
-----------------------------------
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
operation and
maintenance.
-----------------------------------
Sec. 63.8(c)(1)(i).............. Routine and predictable No................... Subpart YYYY does not
SSM. require SSMP.
-----------------------------------
Sec. 63.8(c)(1)(ii)............. SSM not in SSMP........... No................... Subpart YYYY does not
require SSMP.
-----------------------------------
Sec. 63.8(c)(1)(iii)............ Compliance with operation Yes.
and maintenance
requirements.
-----------------------------------
Sec. 63.8(c)(2)-(3)............. Monitoring system Yes.
installation.
-----------------------------------
Sec. 63.8(c)(4)................. Continuous monitoring Yes.................. Except that subpart YYYY
system (CMS) requirements. does not require
continuous opacity
monitoring systems
(COMS).
-----------------------------------
Sec. 63.8(c)(5)................. COMS minimum procedures... No.
-----------------------------------
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 evaluation Yes.................. Except for Sec.
63.8(e)(5)(ii), which
applies to COMS.
-----------------------------------
Sec. 63.8(f)(1)-(5)............. Alternative monitoring Yes.
method.
-----------------------------------

[[Page 1924]]

Sec. 63.8(f)(6)................. Alternative to relative Yes.
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 State Yes.
delegation of
notification requirements.
-----------------------------------
Sec. 63.9(b)(1)-(5)............. Initial notifications..... Yes.
-----------------------------------
Sec. 63.9(c).................... Request for compliance No................... Compliance extensions do
extension. not apply to new or
reconstructed sources.
-----------------------------------
Sec. 63.9(d).................... Notification of special Yes.
compliance requirements
for new sources.
-----------------------------------
Sec. 63.9(e).................... Notification of Yes.
performance test.
-----------------------------------
Sec. 63.9(f).................... Notification of visible No.
emissions/opacity test.
-----------------------------------
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 use.
criterion for alternative
to relative accuracy test
audit (RATA) is exceeded.
-----------------------------------
Sec. 63.9(h)(1)-(6)............. Notification of compliance Yes.................. Except that notifications
status. for sources not
conducting performance
tests are due 30 days
after completion of
performance evaluations.
-----------------------------------
Sec. 63.9(i).................... Adjustment of submittal Yes.
deadlines.
-----------------------------------
Sec. 63.9(j).................... Change in previous Yes.
information.
-----------------------------------
Sec. 63.10(a)................... Administrative provisions Yes.
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 actions No................... Subpart YYYY does not
during SSM. require SSMP so
requirements to
demonstrate conformance
or nonconformance with
SSMP are not applicable.
-----------------------------------
Sec. 63.10(b)(2)(vi)-(xi)....... CMS records............... Yes.
-----------------------------------
Sec. 63.10(b)(2)(xii)........... Record when under waiver.. Yes.
-----------------------------------
Sec. 63.10(b)(2)(xiii).......... Records when using Yes.................. For CO standard if using
alternative to RATA. RATA alternative.
-----------------------------------
Sec. 63.10(b)(2)(xiv)........... Records of supporting Yes.
documentation.
-----------------------------------
Sec. 63.10(b)(3)................ Records of applicability Yes.
determination.
-----------------------------------
Sec. 63.10(c)(1)................ Additional records for Yes.
sources using CEMS.
-----------------------------------
Sec. 63.10(d)(1)................ General reporting Yes.
requirements.
-----------------------------------
Sec. 63.10(d)(2)................ Report of performance test Yes.
results.
-----------------------------------
Sec. 63.10(d)(3)................ Reporting opacity or VE No................... Subpart YYYY does not
observations. contain opacity or VE
standards.
-----------------------------------

[[Page 1925]]

Sec. 63.10(d)(4)................ Progress reports.......... No................... Compliance extensions do
not apply to new or
reconstructed sources.
-----------------------------------
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.
-----------------------------------
Sec. 63.10(e)(4)................ Reporting COMS data....... No................... Subpart YYYY does not
require COMS.
-----------------------------------
Sec. 63.10(f)................... Waiver for recordkeeping Yes.
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 reference Yes.
-----------------------------------
Sec. 63.15...................... Availability of Yes.
information.
----------------------------------------------------------------------------------------------------------------

3. Appendix A to Part 63 is proposed to be amended by adding, in
numerical order, Method 323 to read as follows:

Appendix A to Part 63--Test Methods

* * * * *

Method 323--Measurement of Formaldehyde Emissions from Natural Gas-
Fired Stationary Sources--Acetyl Acetone Derivitization Method

1.0 Introduction

This method describes the sampling and analysis procedures of
the acetyl acetone colorimetric method for measuring formaldehyde
emissions in the exhaust of natural gas-fired, stationary combustion
sources. This method, which was prepared by the Gas Research
Institute (GRI), is based on the Chilled Impinger Train Method for
Methanol, Acetone, Acetaldehyde, Methyl Ethyl Ketone, and
Formaldehyde (Technical Bulletin No. 684) developed and published by
the National Council of the Paper Industry for Air and Stream
Improvement, Inc. (NCASI).1 However, this method has been
prepared specifically for formaldehyde and does not include
specifications (e.g., equipment and supplies) and procedures (e.g.,
sampling and analytical) for methanol, acetone, acetaldehyde, and
methyl ethyl ketone. To obtain reliable results, persons using this
method should have a thorough knowledge of at least Methods 1, 2, 3,
and 4 of 40 CFR part 60, appendix A.

1.1 Scope and Application

1.1.1 Analytes. The only analyte measured by this method is
formaldehyde (CAS Number 50-00-0).
1.1.2 Applicability. This method is for analyzing formaldehyde
emissions from uncontrolled and controlled natural gas-fired,
stationary combustion sources.
1.1.3 Data Quality Objectives. If you adhere to the quality
control and quality assurance requirements of this method, then you
and future users of your data will be able to assess the quality of
the data you obtain and estimate the uncertainty in the
measurements.

2.0 Summary of Method

An emission sample from the combustion exhaust is drawn through
a midget impinger train containing chilled reagent water to absorb
formaldehyde. The formaldehyde concentration in the impinger is
determined by reaction with acetyl acetone to form a colored
derivative which is measured colorimetrically.

3.0 Definitions

[Reserved]

4.0 Interferences

The presence of acetaldehyde, amines, polymers of formaldehyde,
periodate, and sulfites can cause interferences with the acetyl
acetone procedure which is used to determine the formaldehyde
concentration. However, based on experience gained from extensive
testing of natural gas-fired combustion sources using FTIR to
measure a variety of compounds, GRI expects only acetaldehyde to be
potentially present when combusting natural gas. Acetaldehyde has
been reported to be a significant interferent only when present at
concentrations above 50 ppm.4 However, GRI reports that
the concentration of acetaldehyde from gas-fired sources is very low
(typically below the FTIR detection limit of around 0.5 ppmv);
therefore, the potential positive bias due to acetaldehyde
interference is expected to be negligible.

5.0 Safety

5.1 Prior to applying the method in the field, a site-specific
Health and Safety Plan should be prepared. General safety
precautions include the use of steel-toed boots, safety glasses,
hard hats, and work gloves. In certain cases, facility policy may
require the use of fire-resistant clothing while on-site. Since the
method involves testing at high-temperature sampling locations,
precautions must be taken to limit the potential for exposure to
high-temperature gases and surfaces while inserting or removing the
sample probe. In warm locations, precautions must also be taken to
avoid dehydration.
5.2 Potential chemical hazards associated with sampling include
formaldehyde, nitrogen oxides (NO_X), and carbon monoxide
(CO). Formalin solution, used for field spiking, is an aqueous
solution containing formaldehyde and methanol. Formaldehyde is a
skin, eye, and respiratory irritant and a carcinogen, and should be
handled accordingly. Eye and skin contact and inhalation of
formaldehyde vapors should be avoided.
Natural gas-fired combustion sources can potentially emit CO at
toxic concentrations. Care should be taken to minimize exposure to
the sample gas while inserting or removing the sample probe. If the
work area is enclosed, personal CO monitors should be used to insure
that the concentration of CO in the work area is maintained at safe
levels.
5.3 Potential chemical hazards associated with the analytical
procedures include acetyl acetone and glacial acetic acid. Acetyl
acetone is an irritant to the skin and respiratory system, as well
as being moderately toxic. Glacial acetic acid is highly

[[Page 1926]]

corrosive and is an irritant to the skin, eyes, and respiratory
system. Eye and skin contact and inhalation of vapors should be
avoided. Acetyl acetone and glacial acetic acid have flash points of
41[deg]C (105.8[deg]F) and 43[deg]C (109.4[deg]F), respectively.
Exposure to heat or flame should be avoided.

6.0 Equipment and Supplies

6.1 Sampling Probe. Quartz glass probe with stainless steel
sheath or stainless steel probe.
6.2 Teflon Tubing. Teflon tubing to connect the sample probe to
the impinger train. A heated sample line is not needed since the
sample transfer system is rinsed to recover condensed formaldehyde
and the rinsate combined with the impinger contents prior to sample
analysis.
6.3 Midget Impingers. Three midget impingers are required for
sample collection. The first impinger serves as a moisture knockout,
the second impinger contains 20 mL of reagent water, and the third
impinger contains silica gel to remove residual moisture from the
sample prior to the dry gas meter.
6.4 Vacuum Pump. Vacuum pump capable of delivering a controlled
extraction flow rate between 0.2 and 0.4 L/min.
6.5 Flow Measurement Device. A rotameter or other flow
measurement device to indicate consistent sample flow.
6.6 Dry Gas Meter. A dry gas meter is used to measure the total
sample volume collected. The dry gas meter must be sufficiently
accurate to measure the sample volume to within 2 percent,
calibrated at the selected flow rate and conditions actually
encountered during sampling, and equipped with a temperature sensor
(dial thermometer, or equivalent) capable of measuring temperature
accurately to within 3 [deg]C (5.4 [deg]F).
6.7 Spectrophotometer. A spectrophotometer is required for
formaldehyde analysis, and must be capable of measuring absorbance
at 412 nm.

7.0 Reagents and Standards

7.1 Sampling Reagents

7.1.1 Reagent water. Deionized, distilled, organic-free water.
This water is used as the capture solution, for rinsing the sample
probe, sample line, and impingers at the completion of the sampling
run, in reagent dilutions, and in blanks.
7.1.2 Ice. Ice is necessary to pack around the impingers during
sampling in order to keep the impingers cold. Ice is also needed for
sample transport and storage.

7.2 Analysis

7.2.1 Acetyl acetone Reagent. Prepare the acetyl acetone reagent
by dissolving 15.4 g of ammonium acetate in 50 mL of reagent water
in a 100-mL volumetric flask. To this solution, add 0.20 mL of
acetyl acetone and 0.30 mL of glacial acetic acid. Mix the solution
thoroughly, then dilute to 100 mL with reagent water. The solution
can be stored in a brown glass bottle in the refrigerator, and is
stable for at least two weeks.
7.2.2 Formaldehyde. Reagent grade.
7.2.3 Ammonium Acetate.
7.2.4 Glacial Acetic Acid.

8.0 Sample Collection, Preservation, Storage, and Transport

8.1 Pre-test

8.1.1 Collect information about the site characteristics such as
exhaust pipe diameter, gas flow rates, port location, access to
ports, and safety requirements during a pre-test site survey. You
should then decide the sample collection period per run and the
target sample flow rate based on your best estimate of the
formaldehyde concentration likely to be present. You want to assure
that sufficient formaldehyde is captured in the impinger solution so
that it can be measured precisely by the spectrophotometer. You may
use Equation 323-1 to design your test program. As a guideline for
optimum performance, if you can, design your test so that the liquid
concentration (C_l)is approximately 10 times the assumed
spectrophotometer detection limit of 0.2 ppmw. However, since actual
detection limits are instrument specific, we also suggest that you
confirm that the laboratory equipment can meet or exceed this
detection limit.
8.1.2 Prepare and then weigh the midget impingers prior to
configuring the sampling train. The first impinger is initially dry.
The second impinger contains 20 mL of reagent water, and the third
impinger contains silica gel that is added before weighing the
impinger. Each prepared impinger is weighed and the pre-sampling
weight is recorded to the nearest 0.5 gm.
8.1.3 Assemble the sampling train (see Figure 1). Ice is packed
around the impingers in order to keep them cold during sample
collection. A small amount of water may be added to the ice to
improve thermal transfer.
8.1.4 Perform a sampling system leak-check (from the probe tip
to the pump outlet) as follows: Connect a rotameter to the outlet of
the pump. Close off the inlet to the probe and observe the leak
rate. The leak rate must be less than 2 percent of the planned
sampling rate of 0.2 or 0.4 L/min.
8.1.5 Source gas temperature and static pressure should also be
considered prior to field sampling to ensure adequate safety
precautions during sampling.

8.2 Sample Collection

8.2.1 Set the sample flow rate between 0.2--0.4 L/min, depending
upon the anticipated concentration of formaldehyde in the engine
exhaust. (You may have to refer to published data
5 6 for anticipated concentration levels.) If
no information is available for the anticipated levels of
formaldehyde, use the higher sampling rate of 0.4 L/min.
8.2.2 Record the sampling flow rate every 5-10 minutes during
the sample collection period.
8.2.3 Monitor the amount of ice surrounding the impingers and
add ice as necessary to maintain the proper impinger temperature.
Remove excess water as needed to maintain an adequate amount of ice.
8.2.4 Record measured leak rate, beginning and ending times and
dry gas meter readings for each sampling run, impinger weights
before and after sampling, and sampling flow rates and dry gas meter
exhaust temperature every 5-10 minutes during the run, in a signed
and dated notebook.
8.2.5 If possible, monitor and record the fuel flow rate to the
engine and the exhaust oxygen concentration during the sampling
period. This data can be used to estimate the engine exhaust flow
rate based on the Method 19 approach. This approach, if accurate
fuel flow rates can be determined, is preferred for reciprocating IC
engine exhaust flow rate estimation due to the pulsating nature of
the engine exhaust. The F-Factor procedures described in Method 19
may be used based on measurement of fuel flow rate and exhaust
oxygen concentration. One example equation is Equation 323-2.
8.3 Post-test. Perform a sampling system leak-check (from the
probe tip to pump outlet). Connect a rotameter to the outlet of the
pump. Close off the inlet to the probe and observe the leak rate.
The leak rate must be less than 2 percent of the sampling rate.
Weigh and record each impinger immediately after sampling to
determine the moisture weight gain. The impinger weights are
measured before transferring the impinger contents, and before
rinsing the sample probe and sample line. The moisture content of
the exhaust gas is determined by measuring the weight gain of the
impinger solutions and volume of gas sampled as described in Method
4. Rinse the sample probe and sample line with reagent water.
Transfer the impinger catch to an amber 40-mL VOA bottle with a
Teflon-lined cap. If there is a small amount of liquid in the
dropout impinger (<10 mL), the impinger catches can be combined in
one 40 mL VOA bottle. If there is a larger amount of liquid in the
dropout impinger, use a larger VOA bottle to combine the impinger
catches. Rinse the impingers and combine the rinsate from the sample
probe, sample line, and impingers with the impinger catch. In
general, combined rinse volumes should not exceed 10 mL. The volume
of the rinses during sample recovery should not be excessive as this
may result in your having to use a larger VOA bottle. This in turn
would raise the detection limit of the method since after combining
the rinses with the impinger catches in the VOA bottle, the bottle
should be filled with reagent water to eliminate the headspace in
the sample vial. Keep the sample bottles over ice until analyzed on-
site or received at the laboratory. Samples should be analyzed as
soon as possible to minimize possible sample degradation. Based on a
limited number of previous analyses, samples held in refrigerated
conditions showed some sample degradation over time.

8.4 Quality Control Samples

8.4.1 Field Duplicates. During at least one run, a pair of
samples should be collected concurrently and analyzed as separate
samples. Results of the field duplicate samples should be identified
and reported with the sample results. The percent difference in
exhaust (stack) concentration indicated by field duplicates should
be within 20 percent of their mean concentration. Data are to be
flagged as suspect if the duplicates do not meet the acceptance
criteria.

[[Page 1927]]

8.4.2 Spiked Samples. An aliquot of one sample from each source
sample set should be spiked at 2 to 3 times the formaldehyde level
found in the unspiked sample. It is also recommended that a second
aliquot of the same sample be spiked at around half the level of the
first spike; however, the second spike is not mandatory. The results
are acceptable if the measured spike recovery is 80 to 120 percent.
Use Equation 323-4. Data are to be flagged as suspect if the spike
recovery do not meet the acceptance criteria.
8.4.3 Field Blank. A field blank consisting of reagent water
placed in a clean impinger train, taken to the test site but not
sampled, then recovered and analyzed in the same manner as the other
samples, should be collected with each set of source samples. The
field blank results should be less than 50 percent of the lowest
calibration standard used in the sample analysis. If this criteria
is not met, the data should be flagged as suspect.

9.0 Quality Control

----------------------------------------------------------------------------------------------------------------
QA/QC Specification Acceptance criteria Frequency Corrective action
----------------------------------------------------------------------------------------------------------------
Leak-check--Sections 8.1.4, 8.3...... <2% of Sampling rate... Pre- and Post-sampling. Pre-sampling: Repair
leak and recheck Post-
sampling: Flag data
and repeat run if for
regulatory compliance.
Sample flow rate..................... Between 0.2 and 0.4 L/ Throughout sampling.... Adjust.
min.
VOA vial headspace................... No headspace........... After sample recovery.. Flag data.
Sample preservation.................. Maintain on ice........ After sample recovery.. Flag data.
Sample hold time..................... 14 day maximum......... After sample recovery.. Flag data.
Field Duplicates--Section 8.4.1...... Within 20% of mean of One duplicate per Flag data.
original and duplicate source sample set.
sample.
Spiked Sample--Section 8.4.2......... Recovery between 80 and One spike per source Flag data.
120%. sample set.
Field Blank--Section 8.4.3........... <50% of the lowest One blank per source Flag data.
calibration standard. sample set.
Calibration Linearity--Section 10.1.. Correlation coefficient Per source sample set.. Repeat calibration
of 0.99 or higher. procedures.
Calibration Check Standard--Section Within 10% of One calibration check Repeat check, remake
10.3. theoretical value. per source sample set. standard and repeat,
repeat calibration.
Lab Duplicates--Section 11.2.1....... Within 10% of mean of One duplicate per 10 Flag data.
original and duplicate samples.
sample analysis.
Analytical Blanks--Section 11.2.2.... <50% of the lowest One blank per source Clean glassware/
calibration standard. sample set. analytical equipment
and repeat.
----------------------------------------------------------------------------------------------------------------

10.0 Calibration and Standardization

10.1 Spectrophotometer Calibration. Prepare a stock solution of
10 ppm formaldehyde. Prepare a series of calibration standards from
the stock solution by adding 0, 0.1, 0.3, 0.7, 1.0, and 1.5 mL of
stock solution (corresponding to 0, 1.0, 3.0, 7.0, 10.0, and 15.0
[mu]g formaldehyde, respectively) to screw-capped vials. Adjust each
vial's volume to 2.0 mL with reagent water. Add 2.0 mL of acetyl
acetone reagent, thoroughly mix the solution, and place the vials in
a water bath (or heating block) at 60 [deg]C for 10 minutes. Remove
the vials and allow to cool to room temperature. Transfer each
solution to a cuvette and measure the absorbance at 412 nm using the
spectrophotometer. Develop a calibration curve from the analytical
results of these standards. The acceptance criteria for the
spectrophotometer calibration is a correlation coefficient of 0.99
or higher. If this criteria is not met, the calibration procedures
should be repeated.
10.2 Spectrophotometer Zero. The spectrophotometer should be
zeroed with reagent water when analyzing each set of samples.
10.3--Calibration Checks. Calibration checks consisting of
analyzing a standard separate from the calibration standards must be
performed with each set of samples. The calibration check standard
should not be prepared from the calibration stock solution. The
result of the check standard must be within 10 percent of the
theoretical value to be acceptable. If the acceptance criteria are
not met, the standard must be reanalyzed. If still unacceptable, a
new calibration curve must be prepared using freshly prepared
standards.

11.0 Analytical Procedure

11.1 Sample Analysis. A 2.0-mL aliquot of the impinger catch/
rinsate is transferred to a screw-capped vial. Two mL of the acetyl
acetone reagent are added and the solution is thoroughly mixed. Once
mixed, the vial is placed in a water bath (or heating block) at 60
[deg]C for 10 minutes. Remove the vial and allow to cool to room
temperature. Transfer the solution to a cuvette and measure the
absorbance using the spectrophotometer at 412 nm. The quantity of
formaldehyde present is determined by comparing the sample response
to the calibration curve. Use Equation 323-5. If the sample response
is out of the calibration range, the sample must be diluted and
reanalyzed. Such dilutions must be performed on another aliquot of
the original sample before the addition of the acetyl acetone
reagent. The full procedure is repeated with the diluted sample.

11.2 Analytical Quality Control

11.2.1 Laboratory Duplicates. Two aliquots of one sample from
each source sample set should be prepared and analyzed (with a
minimum of one pair of aliquots for every 10 samples). The percent
difference between aliquot analysis should be within 10 percent of
their mean. Use Equation 323-3. Data are flagged if the laboratory
duplicates do not meet this criteria.
11.2.2 Analytical blanks. Blank samples (reagent water) should
be incorporated into each sample set to evaluate the possible
presence of any cross-contamination. The acceptance criteria for the
analytical blank is less than 50 percent of the lowest calibration
standard. If the analytical blank does not meet this criteria, the
glassware/analytical equipment should be cleaned and the analytical
blank repeated.

12.0 Calculations and Data Analysis

12.1 Nomenclature

A = measured absorbance of 2 mL aliquot
B = estimated sampling rate, lpm
C_l = target concentration in liquid, ppmw
D = estimated stack formaldehyde concentration (ppmv)
E = estimated liquid volume, normally 40, mL (the size of the VOA
used)
c_form = formaldehyde concentration in gas stream, ppmvd
c_form @15_{[percnt]₀₂} = formaldehyde
concentration in gas stream corrected to 15% oxygen, ppmvd
C_sm = measured concentration of formaldehyde in the
spiked aliquot
C_u = measured concentration of formaldehyde in the
unspiked aliquot of the same sample
Cs = calculated concentration of formaldehyde spiking solution added
to the spiked aliquot
df = dilution factor, 1 unless dilution of the sample was needed to
reduce the absorbance into the calibration range
F_d = dry basis F-factor from Method 19, dscf per million
btu
GCV_g = Gross calorific value (or higher heating value),
btu per scf
K_c = spectrophotometer calibration factor, slope of the
least square regression line (Note: Most spreadsheets are capable of
calculating a least squares line.)
K₁ = 0.3855 [deg]K/mm Hg for metric units, (17.65 [deg]R/
in.Hg for English units.)
MW = molecular weight, 30 g/g-mole, for formaldehyde

[[Page 1928]]

24.05 = mole specific volume constant, liters per g-mole
m = mass of formaldehyde in liquid sample, mg
P_std = Standard pressure, 760 mm Hg (29.92 in.Hg)
P_bar = Barometric pressure, mm Hg (in.Hg)
PD = Percent Difference
Q_e = exhaust flow rate, dscf per minute
Q_g = natural gas fuel flow rate, scf per minute
T_m = Average DGM absolute temperature, [deg]K ([deg]R).
T_std = Standard absolute temperature, 293 [deg]K (528
[deg]R).
t = sample time (minutes)
V_m = Dry gas volume as measured by the DGM, dcm (dcf).
V_m(std) = Dry gas volume measured by the DGM, corrected
to standard conditions, dscm (dscf).
V_t = actual total volume of impinger catch/rinsate, mL
V_a = volume (2.0) of aliquot analyzed, mL
X₁ = first value
X₂ = second value
O_2d = oxygen concentration measured, percent by volume,
dry basis
%R = percent recovery of spike
Z_u = volume fraction of unspiked (native) sample
contained in the final spiked aliquot [e.g., Vu/(Vu + Vs), where Vu
+ Vs should = 2.0 mL ]
Z_s = volume fraction of spike solution contained in the
final spiked aliquot [e.g., Vs/(Vu + Vs)]
R = 0.02405 dscm per g-mole, for metric units
Y = Dry Gas Meter calibration factor

12.2 Pretest Design
[GRAPHIC]
[TIFF OMITTED]
TP14JA03.001

12.3 Exhaust Flow Rate
[GRAPHIC]
[TIFF OMITTED]
TP14JA03.002

12.4 Percent Difference.--(Applicable to Field and Lab Duplicates)
[GRAPHIC]
[TIFF OMITTED]
TP14JA03.003

12.5 Percent Recovery of Spike
[GRAPHIC]
[TIFF OMITTED]
TP14JA03.004

12.6 Mass of Formaldehyde in Liquid Sample
[GRAPHIC]
[TIFF OMITTED]
TP14JA03.005

12.7 Dry Sample Gas Volume, Corrected to Standard Conditions
[GRAPHIC]
[TIFF OMITTED]
TP14JA03.007

12.8 Formaldehyde Concentration in Gas Stream
[GRAPHIC]
[TIFF OMITTED]
TP14JA03.008

12.9 Formaldehyde Concentration, Corrected to 15% Oxygen
[GRAPHIC]
[TIFF OMITTED]
TP14JA03.009

13.0 Method Performance

13.1 Precision. Based on a Method 301 validation using quad
train arrangement with post sampling spiking study of the method at
a natural gas-fired IC engine, the relative standard deviation of
six pairs of unspiked samples was 11.2 percent at a mean stack gas
concentration of 16.7 ppmvd.
13.2 Bias. No bias correction is allowed. The single Method 301
validation study of the method at a natural gas-fired IC engine,
indicated a bias correction factor of 0.91 for that set of data. An
earlier spiking study got similar average percent spike recovery
when spiking into a blank sample. This data set is too limited to
justify using a bias correction factor for future tests at other
sources.
13.3 Range. The range of this method for formaldehyde is 0.2 to
7.5 ppmw in the liquid phase. (This corresponds to a range of 0.27
to 10 ppmv in the engine exhaust if sampling at a rate of 0.4 Lpm
for 60 minutes and using a 40 mL VOA bottle.) If the liquid sample
concentration is above this range, perform the appropriate dilution
for accurate measurement. Any dilutions must be taken from new
aliquots of the original sample before reanalysis.
13.4 Sample Stability. Based on a sample stability study
conducted in conjunction with the method validation, sample
degradation for 7 and 14-day hold times does not exceed 2.3 and 4.6
percent, respectively, based on a 95 percent level of confidence.
Therefore, the recommended maximum sample holding time for the
underivatized impinger catch/rinsate is 14 days, where projected
sample degradation is below 5 percent.

14.0 Pollution Prevention

Sample gas from the combustion source exhaust is vented to the
atmosphere after passing through the chilled impinger sampling
train. Reagent solutions and samples should be collected for
disposal as aqueous waste.

15.0 Waste Management

Standards of formaldehyde and the analytical reagents should be
handled according to the Material Safety Data Sheets.

16.0 References

1 National Council of the Paper Industry for Air and
Stream Improvement, Inc., ``Volatile Organic Emissions from Pulp and
Paper Mill Sources, Part X--Test Methods, Quality Assurance/Quality
Control Procedures, and Data Analysis Protocols,'' Technical
Bulletin No. 684, December 1994.
2 National Council of the Paper Industry for Air and
Stream Improvement, Inc., ``Field Validation of a Source Sampling
Method for Formaldehyde, Methanol, and Phenol at Wood Products
Mills,'' 1997 TAPPI International Environmental Conference.
3 Roy F. Weston, Inc., ``Formaldehyde Sampling Method
Field Evaluation and Emission Test Report for Georgia-Pacific
Resins, Inc., Russellville, South Carolina,'' August 1996.
4 Hoechst Celanese Method CL 8-4, ``Standard Test
Method for Free Formaldehyde in Air Using Acetyl acetone,'' Revision
0, September 1986.
5 Shareef, G.S., et al. ``Measurement of Air Toxic
Emissions from Natural Gas-Fired Internal Combustion Engines at
Natural Gas Transmission and Storage Facilities.'' Report No. GRI-
96/0009.1, Gas Research Institute, Chicago, Illinois, February 1996.
6 Gundappa, M., et al. ``Characteristics of
Formaldehyde Emissions from Natural Gas-Fired Reciprocating Internal
Combustion Engines in Gas Transmission. Volume I: Phase I Predictive
Model for Estimating Formaldehyde Emissions from 2-Stroke Engines.''
Report No. GRI-97/0376.1, Gas

[[Page 1929]]

Research Institute, Chicago, Illinois, September 1997.

17.0 Tables, Diagrams, Flowcharts, and Validation Data

BILLING CODE 6560-50-P
[GRAPHIC]
[TIFF OMITTED]
TP14JA03.010

[FR Doc. 03-86 Filed 1-13-03; 8:45 am]
BILLING CODE 6560-50-C

Notices For
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994

National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines

Local Navigation