[Federal Register Volume 68, Number 9 (Tuesday, January 14, 2003)]
[Proposed Rules]
[Pages 1888-1929]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 03-86]



[[Page 1887]]

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Part II





Environmental Protection Agency





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40 CFR Part 63



National Emission Standards for Hazardous Air Pollutants for Stationary 
Combustion Turbines; Proposed Rule

  Federal Register / Vol. 68, No. 9 / Tuesday, January 14, 2003 / 
Proposed Rules  

[[Page 1888]]


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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.

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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 [email protected].

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

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                   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.epa.gov/edocket/ 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 [email protected], 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.

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    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

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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 NOX 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 
NOX, 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 NOX 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., NOX, 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 NOX 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 NOX 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 NOX 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).

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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 NOX, 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 NOX 
emitting and are permitted to continuously attain the permitted 
NOX levels. The same technology that results in the 
maintenance of low NOX 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 NOX 
permit levels, or low NOX levels characteristic of lean 
premix combustor turbines (e.g. NOX 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 NOX 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 NOX 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_mix 08--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.
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    \5\ ibid.

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[[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 (65 FR 67249, November 6, 2000), requires EPA 
to develop an accountable process to ensure ``meaningful and timely 
input by tribal officials in the development of 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 
[email protected], 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 NOX 
levels, as permitted by an enforcement agency, or if there are not 
permit levels and you are not attaining low NOX levels 
characteristic of lean premix combustion (e.g., NOX 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:

Ci = CO concentration at inlet of the oxidation catalyst 
emission control device
Co = 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 (NOX), 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 (Cl)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
Cl = target concentration in liquid, ppmw
D = estimated stack formaldehyde concentration (ppmv)
E = estimated liquid volume, normally 40, mL (the size of the VOA 
used)
cform = formaldehyde concentration in gas stream, ppmvd
cform @15[percnt]02 = formaldehyde 
concentration in gas stream corrected to 15% oxygen, ppmvd
Csm = measured concentration of formaldehyde in the 
spiked aliquot
Cu = 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
Fd = dry basis F-factor from Method 19, dscf per million 
btu
GCVg = Gross calorific value (or higher heating value), 
btu per scf
Kc = 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
Pstd = Standard pressure, 760 mm Hg (29.92 in.Hg)
Pbar = Barometric pressure, mm Hg (in.Hg)
PD = Percent Difference
Qe = exhaust flow rate, dscf per minute
Qg = natural gas fuel flow rate, scf per minute
Tm = Average DGM absolute temperature, [deg]K ([deg]R).
Tstd = Standard absolute temperature, 293 [deg]K (528 
[deg]R).
t = sample time (minutes)
Vm = Dry gas volume as measured by the DGM, dcm (dcf).
Vm(std) = Dry gas volume measured by the DGM, corrected 
to standard conditions, dscm (dscf).
Vt = actual total volume of impinger catch/rinsate, mL
Va = volume (2.0) of aliquot analyzed, mL
X1 = first value
X2 = second value
O2d = oxygen concentration measured, percent by volume, 
dry basis
%R = percent recovery of spike
Zu = volume fraction of unspiked (native) sample 
contained in the final spiked aliquot [e.g., Vu/(Vu + Vs), where Vu 
+ Vs should = 2.0 mL ]
Zs = 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
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12.8 Formaldehyde Concentration in Gas Stream
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12.9 Formaldehyde Concentration, Corrected to 15% Oxygen
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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
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[FR Doc. 03-86 Filed 1-13-03; 8:45 am]
BILLING CODE 6560-50-C