[Federal Register Volume 63, Number 25 (Friday, February 6, 1998)]
[Proposed Rules]
[Pages 6288-6336]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-2714]



[[Page 6287]]

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Part II





Environmental Protection Agency





_______________________________________________________________________



40 CFR Part 63



National Emission Standards for Hazardous Air Pollutants: Oil and 
Natural Gas Production and Natural Gas Transmission and Storage; 
Proposed Rule

  Federal Register / Vol. 63, No. 25 / February 6, 1998 / Proposed 
Rules  

[[Page 6288]]



ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[AD-FRL-5955-1]
RIN 2060-AE34


National Emission Standards for Hazardous Air Pollutants: Oil and 
Natural Gas Production and Natural Gas Transmission and Storage

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rules and notice of public hearing.

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

SUMMARY: These proposed national emission standards for hazardous air 
pollutants (NESHAP) would limit emissions of hazardous air pollutants 
(HAP) from oil and natural gas production and natural gas transmission 
and storage facilities. These proposed rules would implement section 
112 of the Clean Air Act (Act) and are based on the Administrator's 
determination that oil and natural gas production and natural gas 
transmission and storage facilities emit HAP identified on the EPA's 
list of 188 HAP.
    The EPA estimates that approximately 65,000 megagrams per year (Mg/
yr) of HAP are emitted from major and area sources in these source 
categories. The primary HAP emitted by the facilities covered by these 
proposed standards include benzene, toluene, ethyl benzene, mixed 
xylenes (collectively referred to as BTEX), and n-hexane. Benzene is 
carcinogenic and all can cause toxic effects following exposure. The 
EPA estimates that these proposed NESHAPs would reduce HAP emissions in 
the oil and natural gas production source category by 57 percent and in 
the natural gas transmission storage source category by 36 percent.
    Also, the EPA is amending the list of source categories established 
under section 112(c) of the Act. Natural gas transmission and storage 
is being listed as a category of major sources and oil and natural gas 
production is being listed as a category of area sources in addition to 
its major source listing.

DATES: Comments. Comments must be received on or before April 7, 1998. 
For information on submitting electronic comments see the Supplementary 
Information section of this document.
    Public Hearing. A public hearing will be held, if requested, to 
provide interested persons an opportunity for oral presentation of 
data, views, or arguments concerning the proposed standards for the oil 
and natural gas production and the natural gas transmission and 
storage. If anyone contacts the EPA requesting to speak at a public 
hearing by March 9, 1998, a public hearing will be held on March 23, 
1998, beginning at 9:30 a.m. Persons interested in attending the 
hearing should notify Ms. JoLynn Collins, telephone (919) 541-5671, 
Waste and Chemical Processes Group (MD-13), to verify that a hearing 
will occur.
    Request to Speak at a Hearing. Persons wishing to present oral 
testimony must contact the EPA by March 9, 1998, by contacting Ms. 
JoLynn Collins, Waste and Chemical Processes Group (MD-13), U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711, 
telephone (919) 541-5671.

ADDRESSES: Comments. Comments should be submitted (in duplicate, if 
possible) to: Air and Radiation Docket and Information Center (MC-
6102), Attention: Docket No. A-94-04, U.S. Environmental Protection 
Agency, 401 M Street, SW, Washington, DC 20460. The EPA requests that a 
separate copy of comments also be sent to Stephen Shedd, USEPA, Office 
of Air Quality Planning and Standards, Research Triangle Park, NC 
27711, telephone (919) 541-5397, fax (919) 541-0246 and E-mail: 
[email protected]. Comments and data may also be submitted 
electronically by following the instructions listed in Supplementary 
Information. No confidential business information (CBI) should be 
submitted through e-mail.
    Background Information Document. The background information 
document (BID) may be obtained from the U.S. Environmental Protection 
Library (MD-35), Research Triangle Park, NC 27711, telephone (919) 541-
2777. Please refer to ``National Emissions Standards for Hazardous Air 
Pollutants for Source Categories: Oil and Natural Gas Production and 
Natural Gas Transmission and Storage--Background Information for 
Proposed Standards'' (EPA-453/R-94-079a, April 1997) for the BID. This 
document may also be obtained electronically from the EPA's Technology 
Transfer Network (TTN) (see SUPPLEMENTARY INFORMATION for access 
information).
    Docket. A docket, No. A-94-04, containing information considered by 
the EPA in development of the proposed standards for the oil and 
natural gas production and natural gas transmission and storage source 
categories, is available for public inspection between 8:00 a.m. and 
4:00 p.m., Monday through Friday (except for Federal holidays) at the 
following address: U.S. Environmental Protection Agency, Air and 
Radiation Docket and Information Center (MC-6102), 401 M Street SW., 
Washington DC 20460, telephone: (202) 260-7548. The docket is located 
at the above address in Room M-1500, Waterside Mall (ground floor). The 
proposed regulations, BID, and other supporting information are 
available for inspection and copying. A reasonable fee may be charged 
for copying.

FOR FURTHER INFORMATION CONTACT: For information concerning the 
proposed standards, contact Ms. Martha Smith, Waste and Chemical 
Processes Group, Emission Standards Division (MD-13), U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711, 
(919) 541-2421, or electronically at: [email protected].

SUPPLEMENTARY INFORMATION: Regulated Entities. Regulated categories and 
entities include:

------------------------------------------------------------------------
             Category                  Examples of regulated entities   
------------------------------------------------------------------------
Industry..........................  Condensate tank batteries, glycol   
                                     dehydration units, natural gas     
                                     processing plants, and natural gas 
                                     transmission and storage           
                                     facilities.                        
------------------------------------------------------------------------

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be regulated by this 
action. This table lists the types of entities that the EPA is now 
aware could potentially be regulated by this action. Other types of 
entities not listed in the table could also be regulated. To determine 
whether your facility is regulated by this action, you should carefully 
examine the applicability criteria in Secs. 63.760 and 63.1270 of the 
rules. If you have questions regarding the applicability of this action 
to a particular entity, consult the person listed in the preceding FOR 
FURTHER INFORMATION CONTACT section.
    Electronic comments can be sent directly to EPA at: A-and-R-
D[email protected]. Electronic comments must be submitted as an 
ASCII file avoiding the use of special characters and any form of 
encryption. Comments and data will also be accepted on disks in 
WordPerfect in 5.1 or 6.1 file format or ASCII file format. All 
comments and data in electronic form must be identified by the docket 
number A-94-04. Electronic comments on this proposed rule may be filed 
online at many Federal Depository Libraries.
    This document, the proposed regulatory texts, and BID are available 
in Docket No. A-94-04 or by request from the EPA's Air and Radiation 
Docket and Information Center (see ADDRESSES) or

[[Page 6289]]

access through the EPA web site at: http://www.epa.gov/ttn/oarpg.
    The following outline is provided to aid in reading the preamble to 
the proposed oil and natural gas production and natural gas 
transmission and storage NESHAPs.

I. Background
    A. Purpose of the Proposed Standards
    B. Technical Basis for the Proposed Standards
    C. Stakeholder and Public Participation
II. Source Category Descriptions
    A. Source Category List
    B. Hazardous Air Pollutant Types
    C. Facility Types
III. Summary of Proposed Standards
    A. Proposed Standards for Oil and Natural Gas Production for 
Major and Area Sources
    B. Proposed Standards for Natural Gas Transmission and Storage 
for Major Sources
IV. Summary of Environmental, Energy, and Economic Impacts
    A. HAP Emission Reductions
    B. Secondary Environmental Impacts
    C. Energy Impacts
    D. Cost Impacts
    E. Economic Impacts
V. Area Source Finding
VI. Glycol Dehydration Unit Nationwide HAP Emissions Estimates
VII. Definition of Major Source for the Oil and Natural Gas Industry
    A. Definition of ``Associated Equipment''
    B. Definition of Facility
VIII. Rationale for Proposed Standards
    A. Selection of Hazardous Air Pollutants for Control
    B. Selection of Emission Points
    C. Definition of Affected Source
    D. Determination of MACT Floor
    E. Oil and Natural Gas Production NESHAP-Regulatory Alternatives 
for Existing and New Major Sources
    F. Oil and Natural Gas Production NESHAP-Regulatory Alternatives 
for Existing and New Area Sources
    G. Natural Gas Transmission and Storage NESHAP-Regulatory 
Alternatives for Existing and New Major Sources
    H. Selection of Format
    I. Selection of Test Methods and Procedures
    J. Selection of Monitoring and Inspection Requirements
    K. Selection of Recordkeeping and Reporting Requirements
IX. Relationship to Other Standards and Programs Under the Act
    A. Relationship to the Part 70 and Part 71 Permit Programs
    B. Relationship Between the Oil and Natural Gas Production and 
the Organic Liquids Distribution (Non-Gasoline) Source Categories
    C. Relationship of Proposed Standards to the Pollution 
Prevention Act
    D. Relationship of Proposed Standards to the Natural Gas STAR 
Program
    E. Overlapping Regulations
X. Solicitation of Comments
    A. Potential-to-Emit
    B. Definition of Facility
    C. Interpretation of ``Associated Equipment'' in Section 
112(n)(4) of the Act
    D. Regulation of Area Source Glycol Dehydration Units
    E. HAP Emission Points
    F. Storage Vessels at Natural Gas Transmission and Storage 
Facilities
    G. Cost Impact and Production Recovery Credits
XI. Administrative Requirements
    A. Docket
    B. Paperwork Reduction Act
    C. Executive Order 12866
    D. Regulatory Flexibility
    E. Unfunded Mandates

I. Background

A. Purpose of the Proposed Standards

    The Act was developed, in part,

* * * to protect and enhance the quality of the Nation's air 
resources so as to promote the public health and welfare and 
productive capacity of its population [the Act, section 101(b)(1)].

Oil and natural gas production and natural gas transmission and storage 
facilities are major and area sources of HAP emissions. The EPA 
estimates that approximately 65,000 Mg/yr of HAP are emitted from major 
and area sources in the oil and natural gas production source category 
and 320 Mg/yr of HAP are emitted from major and area sources in the 
natural gas transmission and storage source category. The primary HAP 
associated with oil and natural gas that have been identified include 
BTEX and n-hexane. Exposure to these chemicals has been demonstrated to 
cause adverse health effects. The adverse health effects associated 
with the exposure to these specific HAP are discussed briefly in the 
following paragraphs. In general, these findings have only been shown 
with concentrations higher than those in the ambient air.
    Benzene, one of the HAP associated with this NESHAP, has been 
classified as a known human carcinogen on the basis of observed 
increases in the incidence of leukemia in exposed workers. In addition, 
short-term inhalation of high benzene levels may cause nervous system 
effects such as drowsiness, dizziness, headaches, and unconsciousness 
in humans. At even higher concentrations of benzene, exposure may cause 
death, while lower concentrations may irritate the skin, eyes, and 
upper respiratory tract. Long-term inhalation exposure to benzene may 
cause various disorders of the blood, and toxicity to the immune 
system. Reproductive disorders in women, as well as developmental 
effects in animals, have also been reported for benzene exposure.
    Short-term inhalation of relatively high concentrations of toluene 
by humans may cause nervous system effects such as fatigue, sleepiness, 
headaches, and nausea, as well as irregular heartbeat. Repeated 
exposure to high concentrations may cause additional nervous system 
effects, including incoordination, tremors, decreased brain size, 
involuntary eye movements, and may impair speech, hearing, and vision. 
Long-term exposure of toluene in humans has also been reported to 
irritate the skin, eyes, and respiratory tract, and to cause dizziness, 
headaches, and difficulty with sleep. Children whose mothers were 
exposed to toluene before birth may suffer nervous system dysfunction, 
attention deficits, and minor face and limb defects. Inhalation of 
toluene by pregnant women may also increase the risk of spontaneous 
abortion. Not enough information exists to determine toluene's 
carcinogenic potential.
    Short-term inhalation of high levels of ethyl benzene in humans may 
cause throat and eye irritation, chest constriction, and dizziness. 
Long-term inhalation of ethyl benzene by humans may cause blood 
disorders. Animal studies have reported blood, liver, and kidney 
effects associated with ethyl benzene inhalation. Birth defects have 
been reported in animals exposed via inhalation; whether these effects 
may occur in humans is not known. Not enough information exists 
concerning ethyl benzene for determination of its carcinogenic 
potential.
    Short-term inhalation of high levels of mixed xylenes (a mixture of 
three closely-related compounds) in humans may cause irritation of the 
nose and throat, nausea, vomiting, gastric irritation, mild transient 
eye irritation, and neurological effects. Long-term inhalation of high 
levels of xylene in humans may result in nervous system effects such as 
headaches, dizziness, fatigue, tremors, and incoordination. Other 
reported effects noted include labored breathing, heart palpitation, 
severe chest pain, abnormal heart functioning, and possible effects on 
the blood and kidneys. Developmental effects have been reported from 
xylene exposure via inhalation in animals. Not enough information 
exists to determine the carcinogenic potential of mixed xylenes.
    Short-term inhalation of high levels of n-hexane in humans may 
cause mild central nervous system effects (dizziness, giddiness, slight 
nausea, and headache) and irritation of the skin and mucous membranes. 
Long-term inhalation exposure of high levels of n-hexane in humans has 
been reported to

[[Page 6290]]

cause nerve damage expressed as numbness in the extremities, muscular 
weakness, blurred vision, headache, and fatigue. Reproductive effects 
have been reported in animals after inhalation exposure (testicular 
damage in rats). Not enough information exists concerning n-hexane for 
determination of its carcinogenic potential.
    The EPA estimates that the proposed NESHAP would reduce HAP 
emissions from those impacted HAP emission points in the oil and 
natural gas production source category by 57 percent and would reduce 
HAP emissions from triethylene glycol (TEG) dehydration units in the 
natural gas transmission and storage source category by 36 percent.

B. Technical Basis for the Proposed Standards

    Section 112 of the Act regulates stationary sources of HAP. Section 
112(b) of the Act lists 188 chemicals, compounds or groups of chemicals 
as HAP. The EPA is directed by section 112 to regulate the emission of 
HAP from stationary sources by establishing national emission 
standards.
    Section 112(a)(1) of the Act defines a major source as:

* * * any stationary source or group of stationary sources located 
within a contiguous area and under common control that emits or has 
the potential-to-emit considering controls, in the aggregate 10 tons 
per year (tpy) or more of any HAP or 25 tpy or more of any 
combination of HAP.

An area source is defined as a stationary source that is not a major 
source.

    For major sources, the statute requires the EPA to establish 
standards to reflect the maximum degree of reduction in HAP emissions 
through application of maximum achievable control technology (MACT). 
Further, the EPA must establish standards that are no less stringent 
than the level of control defined under section 112(d)(3) of the Act, 
often referred to as the MACT floor. The proposed standards for major 
sources in the oil and natural gas production and natural gas 
transmission and storage source categories are based on the MACT floor 
for these source categories.
    In developing standards for area sources of HAP emissions, the EPA 
has discretion to establish standards based on (1) MACT, (2) generally 
available control technology (GACT), or (3) management practices that 
reduce the emission of HAP. The proposed standards for selected area 
source TEG dehydration units are based on GACT. There is no statutory 
``floor'' level of control for GACT.
    Information on industry processes and operations, HAP emission 
points, and HAP emission reduction techniques were collected through 
section 114 questionnaires that were distributed to companies in the 
oil and natural gas production and natural gas transmission and storage 
source categories. The companies provided information on representative 
facilities.
    This information was used, in part, as the technical basis in 
determining the MACT level of control for the emission points covered 
under the proposed standards. In addition to information collected in 
the questionnaires, the EPA considered information available in the 
general literature, as well as information submitted by industry on 
technical issues subsequent to the questionnaire responses.

C. Stakeholder and Public Participation

    Numerous representatives of the oil and natural gas industry and 
other interested parties were consulted in the development of the 
proposed standards. Industry assisted in data gathering, arranging site 
visits, technical review, and sharing of industry-sponsored data 
collection activities. A data base comprised of all industry-supplied 
information was developed in the evaluation of HAP emissions and air 
emission controls for these proposed standards.
    Estimates of HAP emissions from representative facilities in each 
industry segment were developed by the EPA. To estimate HAP emissions 
from glycol dehydration units in both the oil and natural gas 
production and natural gas transmission and storage source categories, 
the EPA utilized an emission model, GRI-GLYCalc TM (Version 
3.0), developed by the Gas Research Institute (GRI). Inputs used by the 
EPA for this model were primarily developed from information supplied 
by industry.
    The trade associations and organizations that participated in the 
development of the proposed rules on a regular basis include (1) the 
American Petroleum Institute (API) and (2) GRI. Other interested 
parties that participated in the development of the proposed standards 
include the Independent Petroleum Association of America (IPAA), the 
Audubon Society, the Interstate Oil and Gas Compact Commission (IOGCC), 
the American Gas Association (AGA), and the Interstate Natural Gas 
Association of America (INGAA).
    These interested parties, in addition to individual companies in 
the oil and natural gas industry, were offered the opportunity to 
provide technical review and comment during the development of the 
proposed standards. In addition, interested parties provided technical 
review and comment on the preliminary draft BID and preliminary draft 
standards.
    Representatives from other EPA offices and programs were included 
in the regulatory development process. These representatives' 
responsibilities included review and internal concurrence with the 
proposed standards. Therefore, the EPA believes that the impact of 
these proposed regulations to other EPA offices and programs has been 
adequately considered during the development of these regulations.
    This notice also solicits comment on the proposed standards and 
offers a chance for a public hearing on the proposals in order to 
provide interested persons the opportunity for oral presentation of 
data, views, or arguments concerning the proposed standards.

II. Source Category Descriptions

A. Source Category List

    Oil and natural gas production was included on the EPA's initial 
list of categories of major sources of HAP emissions established under 
section 112(c)(1) of the Act. This list was published on July 16, 1992 
(57 FR 31576).
    The EPA included natural gas transmission and storage in the 
proposed initial listing of source categories that was published in 
1991. The EPA's preliminary analysis that led to natural gas 
transmission and storage being listed as a source category was based on 
the estimated emissions of the HAP ethylidene dichloride (1,1-
dichloroethane). Comments received on the proposed initial list 
indicated that these estimates were not accurate.
    Based on its review of comments for the final initial list, the EPA 
decided that it did not have sufficient available information that 
supported that this source category could contain a major source of 
HAP. Thus, the natural gas transmission and storage source category was 
not included as a distinct source category in the final initial list of 
source categories of major sources of HAP.
    In the development of the proposed standards for the oil and 
natural gas production source category, information was obtained on 
glycol dehydration unit BTEX emissions that are representative of both 
oil and natural gas production facilities and natural gas transmission 
and storage facilities. The information obtained indicates that natural 
gas transmission and storage facilities have

[[Page 6291]]

the potential to be major HAP sources. In addition, industry has stated 
to the EPA that there are major source TEG dehydration units in the 
natural gas transmission and storage source category. Therefore, the 
EPA is amending the source category list to add the natural gas 
transmission and storage source category as a major source category 
and, with this notice, is proposing a regulation that would apply to 
major sources in this source category.
    The EPA has made a determination that there are area sources in the 
oil and natural gas production source category that present a threat of 
adverse effects to human health and the environment. Based on this 
determination, referred to as an ``area source finding,'' the EPA is 
amending the source category list to add oil and natural gas production 
to the list of area source categories established under section 
112(c)(1) of the Act. The area source finding supporting this listing 
is discussed in section V of this preamble.
    Glycol dehydration units located at natural gas transmission and 
storage facilities have similar HAP emissions and emission potential to 
those located at oil and natural gas production facilities. The EPA is 
currently evaluating whether TEG dehydration units located at natural 
gas transmission and storage facilities that are area sources 
constitute an unacceptable risk to public health or the environment and 
should be listed and regulated as an area source. The EPA is soliciting 
information and comment in this notice regarding the location and HAP 
emissions from area source TEG dehydration units in the natural gas 
transmission and storage source category (see sections V and X for 
further discussion).
    The documentation supporting the listing of oil and natural gas 
production as a source category (``Documentation for Developing the 
Initial Source Category List,'' EPA-450/3-91-030, July 1992) describes 
the source category as including

* * * the processing and upgrading of crude oil prior to entering 
the petroleum refining process and natural gas prior to entering the 
transmission line.

During the development of the proposed rules, industry requested that 
HAP emissions associated with distribution of hydrocarbon liquids after 
the point of custody transfer be addressed within the scope of the 
organic liquids distribution (non-gasoline) source category and not the 
oil and natural gas production source category. Custody transfer, as 
defined in a previous rule, means transfer, after processing and/or 
treatment in the producing operations, from storage vessels or 
automatic transfer facilities to pipelines or any other forms of 
transportation. Industry representatives commented that there are 
differences in the HAP emission potential from facilities involved in 
the distribution of petroleum liquids after the point of custody 
transfer relative to other processes and operations in the oil and 
natural gas production source category.
    The EPA, after evaluation of industry comments, is proposing that 
HAP emissions associated with the distribution of hydrocarbon liquids 
after the point of custody transfer would be more appropriately 
addressed as part of the organic liquids distribution (non-gasoline) 
source category. Therefore, the proposed rule for the oil and natural 
gas production source category would not apply to those facilities that 
distribute hydrocarbon liquids after the point of custody transfer (see 
proposed regulation for definition of custody transfer).
    Facilities involved in the organic liquids distribution (non-
gasoline) sector of the petroleum industry include (but are not limited 
to) gathering stations, trunk-line stations, and station storage vessel 
farms. The organic liquids distribution (non-gasoline) source category 
is scheduled for regulation under section 112 of the Act by November 
15, 2000.
    The EPA plans to define the organic liquids distribution (non-
gasoline) source category (within that rulemaking) as including those 
facilities that distribute hydrocarbon liquids after the point of 
custody transfer. This will eliminate the potential for overlapping 
regulatory requirements between the oil and natural gas production and 
organic liquids distribution (non-gasoline) source categories.

B. Hazardous Air Pollutant Types

    The primary HAP associated with the oil and natural gas production 
and natural gas transmission and storage source categories include BTEX 
and n-hexane. In addition, available information indicates that 2,2,4-
trimethylpentane (iso-octane), formaldehyde, acetaldehyde, naphthalene, 
and ethylene glycol may be present in certain process and emission 
streams. Carbon disulfide (CS2), carbonyl sulfide (COS), and 
BTEX may also be present in the tail gas streams from amine treating 
and sulfur recovery units.

C. Facility Types

    The oil and natural gas production and natural gas transmission and 
storage source categories consist of various facilities used to recover 
and treat products (hydrocarbon liquids and gases) from production 
wells. These source categories include the processing, storage, and 
transport of these products to (1) the point of custody transfer for 
the oil and natural gas production source category or (2) the point of 
delivery to the local distribution company (LDC) or final end user for 
the natural gas transmission and storage source category. The 
facilities in the oil and natural gas production source category that 
the EPA is proposing requirements for include (1) glycol dehydration 
units, (2) condensate tank batteries, and (3) natural gas processing 
plants. The EPA is also proposing requirements for glycol dehydration 
units located at facilities in the natural gas transmission and storage 
source category.
1. Glycol Dehydration Units
    The most widely used dehydration process in these source categories 
is glycol dehydration. TEG dehydration units account for the majority 
of glycol dehydration units, with ethylene glycol (EG) and diethylene 
glycol (DEG) dehydration units accounting for the remaining population 
of glycol dehydration units. In the dehydration process, natural gas is 
contacted with glycol to remove water present in the natural gas. Some 
portion of the HAP present in the natural gas are also removed by the 
glycol. The ``rich'' glycol is then heated in a reboiler to remove 
water vapor and other contaminants prior to recirculation in the 
process. The reboiler vent of the glycol dehydration unit is the 
primary identified source of HAP emissions for these source categories.
2. Tank Batteries
    The term ``tank battery'' refers to the collection of process 
equipment used to separate, upgrade, store, and transfer extracted 
petroleum products and separated streams. These facilities handle crude 
oil and condensate up to the custody transfer of these products to 
facilities in the organic liquids distribution (non-gasoline) source 
category. Separation and dehydration of natural gas can also occur at a 
tank battery. A tank battery may serve an individual production well or 
a collection of wells in the field.
    Tank batteries can be broadly classified as black oil tank 
batteries or condensate tank batteries. Black oil means hydrocarbon 
(petroleum) liquid with a gas-to-oil ratio (GOR) less than 50 cubic 
meters (m3) (1,750 cubic feet (ft3)) per barrel 
and an API gravity less than

[[Page 6292]]

40 degrees ( deg.). Condensate means hydrocarbon liquid that condenses 
because of changes in temperature, pressure, or both, and remains 
liquid at standard conditions. The majority of tank batteries, 
approximately 85 percent, are black oil tank batteries and the 
remainder are condensate tank batteries.
    The primary identified HAP emission points at tank batteries 
include (1) process vents associated with glycol dehydration units and 
(2) tanks and vessels storing volatile oils, condensate, and other 
similar hydrocarbon liquids that have a flash emission potential. 
Condensate tank batteries typically incorporate a glycol dehydration 
unit in the process system.
    The EPA proposes to exempt from the oil and natural gas production 
NESHAP those facilities that handle black oil exclusively. This 
exemption is based on the EPA's proposed interpretation of associated 
equipment in section 112(n)(4) of the Act. The EPA is proposing that 
associated equipment be defined as all equipment associated with a 
production well up to the point of custody transfer, except that glycol 
dehydration units and storage vessels with flash emissions would not be 
associated equipment. The EPA believes that this proposed definition 
will provide the relief that Congress intended in section 112(n)(4) for 
the numerous, widely dispersed, small emission points in the oil and 
natural gas production source category (such as black oil tank 
batteries) while preserving the EPA's ability to require appropriate 
MACT or GACT controls for the most significant identified HAP emission 
points in this source category (see section VII of this preamble for a 
detailed discussion of associated equipment).
3. Natural Gas Processing Plants
    A natural gas processing plant conditions natural gas by separating 
natural gas liquids (NGLs) from field natural gas and, in addition, may 
fractionate the NGLs into separate components such as ethane, propane, 
butane, and natural gasoline. Natural gas processing may also include 
amine treating and sulfur recovery units onsite to treat natural gas 
streams.
    The primary identified HAP emission points at natural gas 
processing plants include (1) the glycol dehydration unit reboiler 
vent, (2) storage tanks, particularly those tanks that handle volatile 
oils and condensates that may be significant contributors to overall 
HAP emissions due to flash emissions, and (3) equipment leaks from 
those components handling hydrocarbon streams that contain HAP 
constituents. Other potential HAP emission point process vents are the 
tail gas stream from amine treating processes and sulfur recovery 
units. Limited information has been identified on the potential for HAP 
emissions from these operations. Recent research published by GRI 
indicates that these emission points have the potential to be 
significant sources of HAP emissions. Comment is requested on potential 
HAP emissions and emission rates from these operations and potential 
applicable air emission controls.
4. Natural Gas Transmission and Storage Facilities
    The natural gas transmission and storage source category consists 
of transmission pipelines used for the long distance transport of 
natural gas and underground natural gas storage facilities. These 
facilities typically extend from the natural gas processing plant to 
the local distribution company that delivers natural gas to the final 
end user. In cases where there is no processing, these facilities may 
be located anywhere from the well to the final end user.
    Specific equipment used in natural gas transmission includes the 
land, mains, valves, meters, boosters, regulators, storage vessels, 
dehydrators, compressors, and their driving units and appurtenances, 
and equipment used for transporting gas from a production plant, 
delivery point of purchased gas, gathering system, storage area, or 
other wholesale source of gas to one or more distribution area(s).
    Underground natural gas storage facilities are subsurface 
facilities that store natural gas that has been transferred from its 
original location for the primary purpose of load balancing. Load 
balancing is the process of equalizing the receipt and delivery of 
natural gas (i.e., utilized for stockpiling natural gas for periods of 
high demand, in particular, the winter heating season). Processes and 
operations that may be located at an underground storage facility 
include, but are not limited to, compression and dehydration.
    The primary identified HAP emission point at natural gas 
transmission and storage facilities is the glycol dehydration unit 
reboiler vent.
5. Facility Populations
    There are a large number of glycol dehydration units and tank 
batteries in the United States. The estimated population of glycol 
dehydration units presented in various industry studies range from 
under 20,000 to over 45,000 glycol dehydration units.
    For the purpose of estimating nationwide impacts of this proposed 
NESHAP, the EPA selected 40,000 as the estimated total domestic 
population of all types of dehydration units. Of this total, an 
estimated 38,000 are glycol dehydration units and 2,000 are solid 
desiccant dehydration units.
    Based on typical tank battery configurations and two studies 
conducted for the API, the EPA estimates that there are approximately 
94,000 tank batteries. Of this total, the EPA estimates that there are 
81,000 black oil tank batteries and 13,000 condensate tank batteries.
    In 1996, according to the Oil and Gas Journal, there were 
approximately 700 natural gas processing plants.
    The natural gas transmission and storage source category includes 
over 480,000 kilometers (300,000 miles) of high-pressure transmission 
pipelines and over 300 underground storage facilities. A recent GRI 
report estimates that there are 1,900 compressor stations located along 
transmission pipelines.
    The EPA estimates that approximately 440 existing facilities would 
be affected by the proposed requirements of the production NESHAP for 
major sources. In addition, the EPA estimates that out of an estimated 
37,000 glycol dehydration units at area sources of HAP, 520 existing 
TEG dehydration units would be affected by the proposed standards for 
area sources because they meet or exceed the throughput and benzene 
emission action levels and are also located in counties designated as 
urban (see section III of this preamble for a discussion of area source 
action levels).
    The EPA estimates that about 5 existing facilities would be 
affected by the proposed requirements of the natural gas transmission 
and storage NESHAP for major sources.

III. Summary of Proposed Standards

A. Proposed Standards for Oil and Natural Gas Production for Major and 
Area Sources

    The proposed action would amend title 40, chapter I, part 63 of the 
Code of Federal Regulations (CFR) by adding a new subpart HH--National 
Emission Standards for Hazardous Air Pollutants from Oil and Natural 
Gas Production Facilities. The proposed standards would apply to owners 
and operators of facilities that process, upgrade, or store (1) 
hydrocarbon liquids (with the exception of those facilities that handle 
black oil exclusively) to the point of custody transfer and (2) natural 
gas from the well up to and including the natural gas processing plant. 
Standards are

[[Page 6293]]

proposed that would limit HAP emissions from the following emission 
points at facilities that are major sources of HAP (1) process vents on 
glycol dehydration units, (2) storage vessels with flash emissions, and 
(3) equipment leaks at natural gas processing plants. In addition, 
standards are proposed that would limit HAP emissions from selected 
area source TEG dehydration units.
    As required by the Clean Air Act, the determination of a facility's 
potential-to-emit HAP and, therefore, its status as a major or area 
source, is based on the total of all HAP emissions from all activities 
at a facility, except that emissions from oil or gas exploration or 
production wells (and their associated equipment) and emissions from 
pipeline compressor or pump stations may not be combined. A definition 
of associated equipment is proposed in the proposed rulemaking. Further 
discussion of the definition of associated equipment is presented in 
section VII(A) of this preamble.
1. General Standards
    The proposed standards for oil and natural gas production 
facilities would require that the owner or operator of a major source 
of HAP reduce HAP emissions from glycol dehydration units and storage 
vessels through the application of air emission control equipment or 
pollution prevention measures. In addition, the owner or operator of a 
natural gas processing plant that is a major source would be required 
to reduce HAP emissions from equipment leaks by establishing a leak 
detection and repair (LDAR) program.
    The owner or operator of selected area source TEG dehydration units 
that meet the criteria in the proposed standards would be required to 
reduce HAP emissions from those TEG dehydration units.
    Owners and operators of facilities that process and store black oil 
exclusively would not be subject to the proposed standards. Black oil 
is defined in the proposed oil and natural gas production NESHAP as a 
hydrocarbon liquid with (1) a GOR less than 50 m\3\ (1,750 ft\3\) per 
barrel and (2) an API gravity less than 40 deg..
2. Glycol Dehydration Unit Provisions
    The proposed standards would require that all process vents at 
glycol dehydration units that are located at major HAP sources be 
controlled unless (1) the actual flowrate of natural gas to the glycol 
dehydration unit is less than 85 thousand cubic meters per day (m\3\/
day) (3.0 million standard cubic feet per day (MMSCF/D), on an annual 
average basis, or (2) if benzene emissions from the major source glycol 
dehydration unit are less than 0.9 Mg/yr (1 tpy).
    HAP emissions from process vents at certain area source TEG 
dehydration units would be required to be controlled unless (1) the 
actual flowrate of natural gas to the glycol dehydration unit is less 
than 85 thousand m\3\/day (3.0 MMSCF/D), on an annual average basis, or 
(2) if benzene emissions from the area source glycol dehydration unit 
are less than 0.9 Mg/yr (1 tpy). The proposed requirements are the same 
for existing and new (1) major source glycol dehydration units and (2) 
selected area source TEG dehydration units that meet the specified 
criteria.
    In its analysis of available data, the EPA could not determine any 
level of emission control for those glycol dehydration units with low 
annual natural gas throughputs (less than 85 thousand m\3\/day (3.0 
MMSCF/D), on an annual average basis, or a low benzene emission rate 
(less than 0.9 Mg/yr (1 tpy)). Thus, the EPA is proposing the annual 
throughput and benzene emission rate cutoffs for major sources. In 
addition, the EPA's analysis indicated that control of HAP emissions 
below these cutoff levels was not cost-effective for area source glycol 
dehydration units.
    The EPA is proposing an additional applicability criteria for area 
source TEG dehydration units. The additional proposed criteria would 
limit air emission controls to those selected area source TEG 
dehydration units located in counties classified as urban areas.
    Since the Act does not provide a definition of urban area, the EPA 
used the U.S. Department of Commerce's Bureau of the Census statistical 
data to classify every county in the U.S. into one of three 
classifications (1) Urban-1 counties, (2) Urban-2 counties, or (3) 
Rural counties. Urban-1 counties consist of counties with metropolitan 
statistical areas (MSA) with a population greater than 250,000. Urban-2 
counties are defined as all other counties designated urban by the 
Bureau of Census (areas which comprise one or more central places and 
the adjacent densely settled surrounding fringe that together have a 
minimum of 50,000 persons). The urban fringe consists of contiguous 
territory having a density of at least 1,000 persons per square mile. 
Rural counties are those counties not designated as urban by the Bureau 
of the Census (see docket item A-94-04, II-I-9).
    Figure 1 shows the methodology for assigning counties to each of 
the three classifications. As seen in this diagram, if any part of a 
county contains an Urban-1 area then the entire county is classified as 
an Urban-1 area. For all remaining counties, if greater than 50 percent 
of the population is classified as urban, then that county is 
classified as an Urban-2 area. Counties not designated as Urban-1 or 
Urban-2 by the above method are classified as Rural areas.

BILLING CODE 6560-50-P

[[Page 6294]]

[GRAPHIC] [TIFF OMITTED] TP06FE98.005



BILLING CODE 6560-50-C

Figure 1. Urban/Rural County Classification Methodology

[[Page 6295]]

    Thus, only those area source TEG dehydration units that (1) meet or 
exceed the actual natural gas throughput applicability criteria, (2) 
meet or exceed the benzene emission rate applicability criteria, and 
(3) are located in a county classified as either Urban-1 or Urban-2 
would be required to apply air emission controls on all process vents 
at those units.
    The EPA also evaluated a risk-based distance applicability 
threshold criterion as an alternative to the urban area applicability 
criteria. This method (subsequently referred to as the ``risk-
distance'' method) would target those area source TEG dehydration units 
for regulation that present a potential health risk to exposed 
populations. Under the risk-distance method, each area source TEG 
dehydration unit that may be subject to control, based on actual 
natural gas throughput and benzene emission rate, would have the option 
of conducting a site-specific risk assessment. If this site-specific 
risk assessment resulted in a maximum incremental lifetime cancer risk 
above some threshold level, then the source would be required to 
install controls necessary to reduce that risk to an acceptable level.
    After its evaluation of applicability alternatives, the EPA 
rejected the risk-distance method. The risk based approach would focus 
solely on the protection of the most exposed individual rather than the 
general population. In addition, the EPA believes that the use of the 
urban area as an applicability criteria provides ease of 
implementation. This approach (1) limits the group of affected sources 
to a well defined urban area group, (2) minimizes the non-productive 
burden by exempting the non-urban area group of owners-operators and 
regulatory agencies from compliance assessments, and (3) provides a 
straightforward approach to compliance. Area sources will not need to 
perform analyses to determine if they are affected by the rule if they 
screen out based on the urban area criteria. Only those owner-operators 
of area source TEG dehydration units in urban areas would need to 
evaluate the need for control devices. By contrast, under the risk 
distance approach, all owner-operators would need to do an analysis. 
The EPA is requesting comment, along with supporting documentation, on 
the use of a risk-distance criteria for regulation of area source TEG 
dehydration units as an alternative to the urban area criteria (see 
section X of this preamble).
    Glycol dehydration units that are required to use air emission 
controls would be required to connect each process vent on the glycol 
dehydration unit to an air emission control system that reduces HAP 
emissions by 95 percent or greater (or to an outlet concentration of 20 
parts per million by volume (ppmv) for combustion devices). Pollution 
prevention measures, such as process modifications that reduce the 
amount of HAP emissions generated, would be allowed as an alternative, 
provided they achieve a HAP emission reduction, from uncontrolled 
levels, of 95 percent or greater.
3. Storage Vessel Provisions
    Standards are proposed for existing and new storage vessels 
containing hydrocarbon liquids (other than black oil) that are located 
at major HAP sources. The types of storage vessels that would be 
regulated are those with the potential for flash emissions and that 
have an actual throughput of hydrocarbon liquids equal to or greater 
than 500 barrels per day (BPD).
    Flash emissions from storage occur when a hydrocarbon liquid with a 
high vapor pressure flows from a pressurized vessel into a vessel with 
a lower pressure. Flash emissions typically occur when a hydrocarbon 
liquid, such as condensate, is transferred from a production separator 
to a storage vessel. The proposed standards for storage vessels with 
the potential for flash emissions would require that a storage vessel 
be equipped with an air emission control system if the hydrocarbon 
liquid in the storage vessel has a GOR equal to or greater than 50 m 
\3\ (1,750 ft \3\) per barrel or an API gravity equal to or greater 
than 40 deg. (i.e., the storage vessel has a potential for flash 
emission losses). In addition, the storage vessel must have an actual 
throughput of hydrocarbon liquids equal to or greater than 500 BPD.
    A storage vessel containing a hydrocarbon liquid subject to control 
under the proposed standards would have to be equipped with a cover 
vented through a closed-vent system to a control device that recovers 
or destroys HAP emissions with an efficiency of 95 percent or greater 
(or to an outlet concentration of 20 ppmv for combustion devices). The 
EPA has included the 20 ppmv cutoff for cases where the HAP emission 
concentration is already low, and meeting a 95 percent reduction in 
emissions cannot be achieved.
    A pressurized storage vessel that is designed to operate as a 
closed system would be considered in compliance with the proposed 
requirements for storage vessels. External and internal floating roofs 
that meet certain design criteria would also be allowed.
4. Standards for Equipment Leaks
    The proposed rule requires owners and operators of natural gas 
processing plants that are major HAP sources to control HAP emissions 
from leaks from each piece of equipment that contains or contacts a 
liquid or gas that has a total HAP concentration equal to or greater 
than 10 percent by weight. The proposed equipment leak standards would 
not apply to equipment that operates less than 300 hours per year.
    For equipment subject to these standards at either an existing or 
new source, the owner or operator is required to implement a LDAR 
program and perform equipment modifications, where necessary. Pumps in 
light liquid service, valves in gas/vapor and light liquid service, and 
pressure relief devices in gas/vapor service within a process unit that 
is located on the Alaskan North Slope would be exempt from some of the 
routine LDAR monitoring requirements.
5. Air Emission Control Equipment Requirements
    Specific performance and operating requirements are proposed for 
each control device installed by the owner or operator. Closed-vent 
systems would be required to operate with no detectable emissions. Any 
type of control device would be allowed that reduces the mass content 
of either total organic compounds (less methane and ethane) or total 
HAP in the gases vented to the device by 95 percent by weight or 
greater (or to an outlet concentration of 20 ppmv for combustion 
devices).
    Certain specifications for covers apply based on the type of cover 
and where the cover is installed. Requirements are specified for vapor 
leak-tight covers, and external and internal floating roofs installed 
on storage vessels.
6. Test Methods and Procedures
    An owner or operator must be able to demonstrate that exemption 
from control criteria are met when controls are not applied. For 
example, owners or operators of glycol dehydration units that do not 
install air emission controls because the benzene emission rate from 
the unit is less than 0.9 Mg/yr (1 tpy) must be able to demonstrate 
that the benzene emission rate from the unit is less than 0.9 Mg/yr (1 
tpy). In general, the selected exemption criteria minimize the 
demonstration burden on owners and operators.
    Procedures for demonstrating the HAP emission reduction efficiency 
of control devices and HAP concentration would be consistent with 
procedures established in previously promulgated

[[Page 6296]]

NESHAP that apply to emission sources similar to those addressed in the 
proposed standards. Engineering calculations, modeling (using EPA-
approved models), and previous test results will generally be 
acceptable means of demonstrating compliance, except where such means 
are not conclusive. Test procedures are specified in the proposed rule 
for use when testing is required to demonstrate compliance.
    An alternative test procedure is provided to demonstrate control 
efficiency for when a condenser is used for controlling emissions from 
a glycol dehydration unit reboiler vent. The inclusion of the 
alternative test procedure is appropriate in this standard because of 
difficulties associated with testing the inlet to a condenser in this 
application.
    Procedures and test methods are also specified for detection of 
equipment leaks.
7. Monitoring and Inspection Requirements
    The proposed standards would require that the owner or operator 
periodically inspect and monitor air emission control equipment. Visual 
inspections and leak detection monitoring is required for certain types 
of covers to ensure gaskets and seals are in good condition and for 
closed-vent systems to ensure all fittings remain leak-tight.
    An owner or operator would also be required to visually inspect and 
test covers and closed-vent systems to determine and ensure that they 
operate with no detectable emissions.
    The proposed standards would also require semi-annual inspection 
and leak detection monitoring of covers and annual inspection and leak 
detection monitoring of closed-vent systems.
    The proposed standards would require continuous monitoring of 
control device operation through the use of automated instrumentation. 
The automated instrumentation would be used to measure and record 
control device operating parameters indicating continuous compliance 
with the standards.
8. Recordkeeping and Reporting Requirements
    The recordkeeping and reporting requirements associated with the 
proposed standards would primarily be those specified in the part 63 
General Provisions (40 CFR part 63, subpart A). Major sources would be 
subject to all of the requirements of the General Provisions with the 
exception that (1) owners or operators would be allowed up to one year 
from the effective date of the standards to submit the initial 
notification described in Sec. 63.9, paragraph (b) of subpart A and (2) 
owners or operators are allowed to submit (a) excess emissions and 
continuous monitoring system (CMS) performance reports and (b) startup, 
shutdown, and malfunction reports semi-annually instead of quarterly. 
The EPA selected these specific exceptions due to the large number of 
facilities that would need to submit notifications or reports related 
to the proposed NESHAP. The EPA believes that these exceptions will not 
adversely affect the implementation of the proposed regulation or 
reduce its impact on HAP emissions.
    Area sources would be subject to all of the requirements of the 
General Provisions with the exception that (1) owners or operators of 
existing area sources would be allowed up to one year from the 
effective date of the standards to submit the initial notification 
required by the General Provisions, (2) an owner or operator of an area 
source would not be required to develop and maintain a startup, 
shutdown, and malfunction plan and would only need to submit reports of 
malfunctions when they are not corrected within a specified time 
period, and (3) excess emissions and continuous monitoring reporting 
would be done annually, rather than as required by the General 
Provisions.

B. Proposed Standards for Natural Gas Transmission and Storage for 
Major Sources

    The proposed standards would amend title 40, chapter I, part 63 CFR 
by adding a new subpart HHH--National Emission Standards for Hazardous 
Air Pollutants from Natural Gas Transmission and Storage Facilities. 
The standards would apply to owners and operators of facilities that 
process, upgrade, transport or store natural gas prior to delivery to a 
LDC or a final end user.
1. General Standards
    The proposed rule would require that process vents on glycol 
dehydration units that are located at major HAP sources be controlled 
unless (1) the actual flowrate of natural gas to the glycol dehydration 
unit is less than 85 thousand m3/day (3.0 MMSCF/D), on an 
annual average basis, or (2) if benzene emissions from the major source 
glycol dehydration unit are less than 0.9 Mg/yr (1 tpy). The proposed 
requirements are the same for existing and new glycol dehydration 
units.
    Glycol dehydration units that are required to use air emission 
controls would be required to connect each process vent on the glycol 
dehydration unit to an air emission control system that reduces HAP 
emissions by 95 percent or more or to an outlet concentration of 20 
ppmv for combustion devices. As with the proposed standards for the oil 
and natural gas production NESHAP, pollution prevention measures, such 
as process modifications that reduce the amount of HAP emissions 
generated, would be allowed as an alternative provided they achieve a 
HAP emission reduction of 95 percent or greater or to an outlet 
concentration of 20 ppmv for combustion devices.
    The EPA had insufficient information available to determine whether 
(1) significant HAP-emitting storage vessels warranting control are 
located at natural gas transmission and storage facilities or (2) 
whether the same storage vessel regulatory controls being proposed for 
the oil and natural gas production source category should be applied to 
the natural gas transmission and storage source category. Therefore, 
the EPA is soliciting comment in this proposal (see section X) on 
whether the storage vessels being proposed for control under the oil 
and natural gas production regulation are similar to those that exist 
at natural gas transmission and storage facilities. The EPA is 
specifically requesting information on (1) the type(s) of storage 
vessels at natural gas transmission and storage facilities and (2) 
whether the existing control level of storage vessels at natural gas 
transmission and storage facilities is similar to the existing control 
level of storage vessels at oil and natural gas production facilities.
2. Air Emission Control Equipment Requirements
    Specific performance and operating requirements are proposed for 
each control device installed by the owner or operator. Closed-vent 
systems would be required to operate with no detectable emissions. Any 
type of control device would be allowed that reduces the mass content 
of either total organic compounds (less methane and ethane) or total 
HAP in the gases vented to the device by 95 percent by weight or 
greater (or to an outlet concentration of 20 ppmv for combustion 
devices).
3. Monitoring and Inspection Requirements
    The proposed monitoring and inspection requirements are (1) 
periodic control equipment monitoring, (2) periodic leak detection 
monitoring for closed-vent systems to ensure all fittings remain leak-
tight, (3) semi-annual

[[Page 6297]]

inspection and leak detection monitoring of covers, (4) annual 
inspection and leak detection monitoring of closed-vent systems, and 
(5) continuous monitoring of control device operation. Continuous 
monitoring would require the use of automated instrumentation that 
would measure and record control device compliance operating 
parameters.
4. Recordkeeping and Reporting Requirements
    The recordkeeping and reporting requirements associated with the 
proposed standards would primarily be those specified in the part 63 
General Provisions (40 CFR Part 63 subpart A). Major sources would be 
subject to all of the requirements of the General Provisions, except 
that (1) owners or operators would be allowed up to one year from the 
effective date of the standards to submit the initial notification 
required under Sec. 63.9, paragraph (b) of subpart A and (2) owners or 
operators are allowed to submit excess emissions, CMS performance 
reports, and startup, shutdown, and malfunction reports semi-annually 
instead of quarterly. These exceptions were selected to maintain 
consistency between the major source provisions of these proposed 
regulations.

IV. Summary of Environmental, Energy and Economic Impacts

A. HAP Emission Reductions

    For major sources, it is estimated by the EPA that the proposed oil 
and natural gas production standards for existing sources would result 
in a reduction of HAP emissions from 39,000 Mg/yr to 9,000 Mg/yr. In 
addition, HAP emissions would be reduced by 3,000 Mg/yr for new sources 
over the first 3 years after promulgation of these proposed standards.
    For existing area source TEG dehydration units in the oil and 
natural gas production source category, the EPA estimates that the 
proposed standards would result in a reduction of HAP emissions from 
19,000 Mg/yr to 16,000 Mg/yr. In addition, HAP emissions would be 
reduced by 330 Mg/yr for new sources over the first 3 years after 
promulgation of these proposed standards.
    Tables 1 and 2 present the major and area source emission 
reductions, in addition to other environmental, energy, and cost 
impacts, that the EPA estimates would occur from the implementation of 
the proposed standards for oil and natural gas production.
    The EPA estimates that the proposed natural gas transmission and 
storage standards for existing sources would result in a reduction of 
HAP emissions from 320 Mg/yr to 210 Mg/yr. No new major sources are 
anticipated in the first three years after promulgation of this 
proposed NESHAP. Table 3 presents the major source emission reductions, 
in addition to other environmental, energy, and cost impacts, that the 
EPA estimates would occur from the implementation of the proposed 
standards for existing natural gas transmission and storage facilities.
    The air emission reductions achieved by these proposed standards, 
when combined with the air emission reductions achieved by other 
standards mandated by the Act, will accomplish the primary goal of the 
Act to

* * * enhance the quality of the Nation's air resources so as to 
promote the public health and welfare and the productive capacity of 
its population.

   Table 1.--Summary of Estimated Environmental, Energy, and Economic   
  Impacts for the Proposed Oil and Natural Gas Production Standards for 
                     Existing and New Major Sources                     
------------------------------------------------------------------------
                Impact category                   Existing       New    
------------------------------------------------------------------------
Estimated number of impacted facilities.......          440           44
Emission reductions (Mg/yr):                                            
    HAP.......................................       30,000        3,000
    VOC.......................................       61,000        6,100
    Methane...................................        7,000          700
Secondary environmental emission increases (Mg/                         
 yr):                                                                   
    Sulfur oxides.............................           <1           <1
    Nitrogen oxides...........................            5           <1
    Carbon monoxide...........................           <1           <1
Energy (Kilowatt hours per year)..............       38,000        3,800
Implementation costs (Million of July 1993 $):                          
    Total installed capital...................          6.5          0.7
    Total annual..............................          4.0          0.4
------------------------------------------------------------------------


   Table 2.--Summary of Estimated Environmental, Energy, and Economic   
  Impacts for the Proposed Oil and Natural Gas Production Standards for 
                      Existing and New Area Sources                     
------------------------------------------------------------------------
                Impact category                   Existing       New    
------------------------------------------------------------------------
Estimated number of impacted facilities.......          520           52
Emission reductions (Mg/yr):                                            
    HAP.......................................        3,300          330
    VOC.......................................        7,200          720
    Methane...................................        1,500          150
Secondary environmental emission increases (Mg/                         
 yr):                                                                   
    Sulfur oxides.............................           <1           <1
    Nitrogen oxides...........................            2           <1
    Carbon monoxide...........................           <1           <1
Energy (Kilowatt hours per year)..............         None         None
Implementation costs (Million of July 1993 $):                          
    Total installed capital...................          6.9          0.7
    Total annual..............................          6.2          0.6
------------------------------------------------------------------------


[[Page 6298]]


   Table 3.--Summary of Estimated Environmental, Energy, and Economic   
 Impacts for the Proposed Natural Gas Transmission and Storage Standards
                      for Existing Major Sources a                      
                                                                        
------------------------------------------------------------------------
                      Impact category                          Existing 
------------------------------------------------------------------------
Estimated number of impacted facilities....................            5
Emission reductions (Mg/yr):                                            
    HAP....................................................          110
    VOC....................................................        1,400
    Methane................................................           54
Secondary environmental emission increases (Mg/yr):                     
    Sulfur oxides..........................................         None
    Nitrogen oxides........................................         None
    Carbon monoxide........................................         None
Energy (Kilowatt hours per year)...........................         None
Implementation costs (Thousand of July 1993 $):                         
    Total installed capital................................           57
    Total annual...........................................           46
------------------------------------------------------------------------
a No new major sources are anticipated for this source category after   
  the effective date for new sources and in the first three years       
  following promulgation of the proposed rule.                          

B. Secondary Environmental Impacts

    Other environmental impacts are those associated with operation of 
certain air emission control devices. The adverse secondary air impacts 
would be minimal in comparison to the primary HAP reduction benefits 
from the implementation of the proposed control options for major and 
for selected area oil and natural gas sources. The estimated national 
annual increase in secondary air pollutant emissions that would result 
from the use of a flare to comply with the proposed standards is 
estimated to be less than 1.0 Mg (1.1 ton) for both sulfur oxide 
(SOX) and carbon monoxide (CO) and less than 7 Mg (8 tons) 
for nitrogen oxides (NOX). These estimates are for both 
major and area oil and natural gas production sources. There are no 
anticipated increases in secondary air pollutant emissions from the 
implementation of the proposed control options for major sources at 
natural gas transmission and storage facilities.
    The adverse water impacts anticipated from the implementation of 
control options for the proposed standards are expected to be minimal. 
The water impacts associated with the installation of a condenser 
system for the glycol dehydration unit reboiler vent would be minimal. 
This is because the condensed water collected with the hydrocarbon 
condensate can be directed back into the system for reprocessing with 
the hydrocarbon condensate or, if separated, combined with produced 
water for disposal by reinjection.
    Similarly, the water impacts associated with installation of a 
vapor control system would be minimal. This is because the water vapor 
collected along with hydrocarbon vapors in the vapor collection and 
redirect system can be directed back into the system for reprocessing 
with the hydrocarbon condensate or, if separated, combined with the 
produced water for disposal by reinjection.
    There are no adverse solid waste impacts anticipated from the 
implementation of the proposed standards.

C. Energy Impacts

    Energy impacts are those energy requirements associated with the 
operation of emission control devices. The annual energy requirements 
for each vapor collection/recovery system installed to comply with the 
oil and natural gas production proposed standards is estimated to be 
300 kilowatt hours per year (kw-hr/yr). It is estimated that 
approximately 125 oil and natural gas production major source 
facilities would install one or more of these control options. There 
would be no national energy demand increase from the operation of any 
of the control options analyzed under the proposed oil and natural gas 
production standards for area sources and the national energy demand 
increase for major sources would be an estimated 38,000 kw-hr/yr.
    There would be no national energy demand increase from the 
operation of any of the control options analyzed under the proposed 
natural gas transmission and storage standards for major sources.
    The proposed standards encourage the use of emission controls that 
recover hydrocarbon products, such as methane and condensate, that can 
be used on-site as fuel or reprocessed, within the production process, 
for sale. Thus, the proposed standards have a positive impact 
associated with the recovery of non-renewable energy resources.

D. Cost Impacts

    The estimated total capital cost to comply with the proposed rule 
for major sources in the oil and natural gas production source category 
is approximately $6.5 million. The total capital cost for area sources 
is estimated to be approximately $6.9 million.
    The total estimated net annual cost to industry to comply with the 
proposed requirements for major sources in the oil and natural gas 
production source category is approximately $4.0 million. The total net 
annual cost for area source TEG dehydration units is approximately $6.2 
million. These estimated annual costs include (1) the cost of capital, 
(2) operating and maintenance costs, (3) the cost of monitoring, 
inspection, recordkeeping, and reporting (MIRR), and (4) any associated 
product recovery credits.
    The estimated total capital cost to comply with the proposed rule 
for major sources in the natural gas transmission and storage source 
category is approximately $57,000.
    The total estimated net annual cost to industry to comply with the 
proposed requirements for major sources in the natural gas transmission 
and storage source category is approximately $46,000. As with the oil 
and natural gas production total estimated annual cost to industry, 
this annual cost estimate includes (1) the cost of capital, (2) 
operating and maintenance costs, (3) the cost of MIRR, and (4) any 
associated product recovery credits.
    The EPA's impact analyses consider a facility's ability to handle 
collected vapors. Some remotely located facilities may not be able to 
use collected vapor for fuel or recycle it back into the process. In 
addition, it may not be technically feasible for some facilities to

[[Page 6299]]

utilize the non-condensable vapor streams from condenser systems as an 
alternative fuel source safely. An option for these facilities is to 
combust these vapors by flaring.
    These concerns are reflected in the analyses conducted by the EPA. 
In its analyses, the EPA estimated that (1) 45 percent of all impacted 
facilities will be able to use collected vapors from installed control 
options as an alternative fuel source for an on-site combustion device 
such as a process heater or the glycol dehydration unit firebox, (2) 45 
percent will be able to recycle collected vapors from installed control 
options into a low pressure header system for combination with other 
hydrocarbon streams handled at the facility, and (3) 10 percent will 
direct all collected vapor to an on-site flare.

E. Economic Impacts

    The EPA prepared an economic impact analysis that evaluates the 
impacts of the regulation on affected producers, consumers, and 
society. The economic analysis focuses on the regulatory effects on the 
U.S. natural gas market that is modeled as a national, perfectly 
competitive market for a homogenous commodity. The analysis does not 
include a model to assess the regulatory effects on the world crude oil 
market because the regulation is anticipated to affect less than 5 
percent of the total U.S. crude oil production, and thus, it is 
unlikely to have any influence on the U.S. supply of crude oil or world 
crude oil prices.
    The imposition of regulatory costs on the natural gas market result 
in negligible changes in natural gas prices, output, employment, 
foreign trade, and business closures. Price and output changes as a 
result of the regulation are less than 0.01 of one percent, which is 
significantly less than observed market trends. For example, between 
1992 and 1993 the average change in wellhead price increased by 14 
percent, while domestic production rose by 3 percent.
    The total annual social cost of the regulation is $10 million for 
major and areas sources combined. This value accounts for the 
compliance cost imposed on producers, as well as market adjustments 
that influence the revenues to producers and consumption by end users, 
plus the associated deadweight loss to society of the reallocation of 
resources.

V. Area Source Finding

    The EPA performed an analysis to determine the potential threat of 
adverse effects on human health and the environment due to HAP 
emissions from TEG dehydration units in the oil and natural gas 
production source category and the feasibility and impacts of 
controlling these emissions. The EPA refers to this determination as an 
``area source finding.'' The three primary components of an area source 
finding are (1) a risk assessment conducted for area source TEG 
dehydration units, (2) an evaluation of the technical feasibility and 
associated costs of air emission controls, and (3) an assessment of the 
economic impacts associated with installation of controls.
    The EPA conducted a risk assessment for area source TEG dehydration 
units. The detailed risk assessment is available for review in EPA Air 
Docket A-94-04 and the item entry number is II-B-20.
    The HAP included in the risk assessment were BTEX and n-hexane. 
These are the primary HAP emitted by TEG dehydration units. Toluene, 
ethyl benzene, and n-hexane were evaluated for potential non-cancer 
impacts. The predicted human exposure levels associated with the 
estimated emission of these HAP from area source TEG dehydration units 
did not meet or exceed the levels of concern when compared to the 
available human health reference levels. Mixed xylenes were not 
quantitatively analyzed since the EPA does not have an appropriate 
human health benchmark for assessing human xylene exposure by the 
inhalation pathway.
    The predicted exposures associated with the estimated emission of 
benzene from area source triethylene glycol dehydration units result in 
a maximum individual risk (MIR) of 3 x 10-4 and an annual 
cancer incidence ranging from <1 (assuming all facilities are located 
in rural areas) to 2 (assuming all facilities are located in urban 
areas). The predicted maximum individual risk from this analysis is 
above the EPA's historical action level range of 1 x 10-6 to 
1 x 10-4.
    The types of controls used on TEG dehydration units are able to 
achieve a minimum of 95 percent HAP emission reduction. In the parts of 
the U.S. where the vast majority of natural gas is produced and 
processed, condensers are typically used to reduce emissions from TEG 
dehydration units. Flares are also used to reduce emissions from TEG 
dehydration units.
    Unlike flares, which destroy emissions through combustion, 
condensers capture emissions and allow for the recovery of hydrocarbon 
liquids (condensate) entrained in the emission stream, thus conserving 
a valuable non-renewable resource. Properly operated condensers used at 
TEG dehydration units, that have a flash tank in the overall 
dehydration system design, have a HAP/volatile organic compound (VOC) 
control efficiency of 95 percent.
    The application of condensers and flares to area source TEG 
dehydration units have been observed on actual operating units that are 
typical of those in this industry. Thus, condensers and flares are a 
technically feasible and demonstrated control option for area source 
TEG dehydration units.
    The economic impact analysis performed to evaluate the impacts of 
the major and area source provisions of the proposed regulation 
supports the area source finding. The results of this economic analysis 
are summarized in section IV of this preamble.
    The total annual social cost of the regulation is estimated to be 
$10 million for major and area sources combined (approximately $4.0 
million for major sources and $6.2 million for area sources). This 
value accounts for the compliance cost imposed on producers, as well as 
market adjustments that influence the revenues to producers and 
consumption by end-users, plus the associated deadweight loss to 
society of the reallocation of resources.
    Regulation of area source TEG dehydration units in the oil and 
natural gas production source category is supported by: (1) The 
estimated MIR of 3 x 10-4 for HAP emissions from this area 
source category, (2) technically feasible, effective, and demonstrated 
control options (condensers and flares) that are readily available for 
reducing emissions from area source TEG dehydration units, and (3) the 
results the economic impact analysis that supports the minimal economic 
impact associated with installation of the identified control options.
    The EPA is proposing criteria that would target area source TEG 
dehydration units for control: (1) Which have benzene emissions, (2) 
that can be cost-effectively controlled, and (3) where potential human 
exposures are greatest. These criteria are based on actual natural gas 
throughput, benzene emission rate, and location in a county classified 
as urban.
    The actual natural gas throughput (on an annual average basis) 
action levels for area source TEG dehydration units analyzed by the EPA 
were: (1) 113 thousand m3/day (4.0 MMSCF/D) or greater, (2) 
85 thousand m3/day (3.0 MMSCF/D) or greater, (3) 42 thousand 
m3/day (1.5 MMSCF/D) or greater, and (4) 8.5 thousand 
m3/day (0.3 MMSCF/D) or greater. Based on its evaluation of 
projected impacts and the cost-effectiveness of installed controls, the 
EPA selected 85 thousand m3/day (3.0 MMSCF/D) actual natural 
gas

[[Page 6300]]

throughput as an action level for area source TEG dehydration units.
    The EPA also selected an action level for area sources based on 
actual benzene emissions from each area source TEG dehydration unit. 
Benzene is a known human carcinogen that is typically emitted from 
glycol dehydration units.
    In addition, the EPA selected location as a criterion for control 
based on the county-level urban versus rural location of area source 
TEG dehydration units. Only those area source TEG dehydration units 
located in counties classified as urban (see section III of this 
preamble) and also meeting or exceeding the actual natural gas 
throughput and benzene emission rate action levels would be required to 
install air emission controls for HAP under the proposed rule.

VI. Glycol Dehydration Unit Nationwide HAP Emissions Estimates

    Glycol dehydration units are estimated to account for up to 90 
percent of HAP emissions from the oil and natural gas industry. The EPA 
used GRI-GLYCalcTM Version 3.0, an emissions estimation 
computer program developed by GRI, to estimate HAP emissions from 
glycol dehydration units. This program is regarded within industry and 
the EPA as an accurate simulation tool for estimating emissions of 
organic compounds from glycol dehydration units.
    The EPA developed HAP, VOC, and methane emission estimates for a 
series of representative model glycol dehydration units representative 
of those that operate within this industry. Nationwide emissions were 
then estimated by extrapolating from model glycol dehydration unit 
estimates.
    Two inputs to the methodology used by the EPA to estimate 
nationwide HAP emissions from glycol dehydration units that greatly 
influence the result are: (1) The average HAP concentration of field 
natural gas prior to the first processing stage, and (2) the average 
total number of times that natural gas is dehydrated by all dehydration 
methods between the wellhead and the end user. Based on extensive 
discussions with industry, and review of available information and 
application of engineering judgment, the EPA selected a value of 200 
ppmv for the average BTEX concentration of field natural gas and a 
value of 1.6 for the average number of times that natural gas is 
dehydrated by all dehydration methods between the wellhead and the end 
user. Estimated HAP emissions from all glycol dehydration units (at 
both major and area sources of HAP) are 55,000 Mg/yr.
    The EPA acknowledges that there are uncertainties inherent in any 
estimate of nationwide HAP emissions for industries as large and as 
diverse as the oil and natural gas production or natural gas 
transmission and storage source categories. However, the EPA believes 
that the engineering judgments and methodology used in developing the 
nationwide HAP emissions estimates for these industries are reasonable 
given the available information. The EPA requests comment on the 
methodology and engineering judgments made when developing the 
nationwide glycol dehydration unit HAP emissions estimates for these 
source categories. The EPA specifically requests alternative emission 
estimation methodologies, supported by documentation demonstrating how 
an alternative methodology would yield improved estimates.

VII. Definition of Major Source for the Oil and Natural Gas Industry

A. Definition of ``Associated Equipment''

    Whether a facility is a major source or an area source of HAP 
emissions under section 112 of the Act is important for two reasons. 
First, different requirements may be established for major and area 
sources. Second, a source that is a major source under section 112 of 
the Act is also subject to requirements for major sources under the 
Federal operating permit program authorized by title V of the Act. Area 
sources may also be subject to title V permitting requirements, but the 
EPA has discretion to defer or waive these requirements.
    For some oil and natural gas operations, it is clearly apparent 
what constitutes a facility (e.g., a natural gas processing plant). For 
others, however, it may not be clear what constitutes a facility. This 
is particularly true for field operations in the oil and natural gas 
production source category.
    An oil or natural gas production field, for example, may cover many 
square miles. Within this area, there can be a large number of 
production wells, connected by pipeline, to small (satellite) or larger 
(centralized) locations, such as tank batteries, where storage or 
intermediate processing occurs prior to transmission to further 
processing steps. Leasing and mineral rights agreements can give oil 
and natural gas companies control over a large area of contiguous 
property.
    According to the statutory definition in section 112(a)(1), HAP 
emissions from all emissions points within a contiguous area and under 
common control must be counted in a major source determination. A 
strict interpretation of the statutory definition of major source as 
applied to this industry could mean that HAP emissions must be 
aggregated from emission points separated by considerable distances. 
This distance could be well beyond the distances that separate 
equipment at a typical facility.
    The Congress addressed the unique aspects of the oil and natural 
gas production industry in special provisions included in section 
112(n)(4) of the Act that apply to HAP emissions from oil and natural 
gas wells and pipeline and compressor facilities. Section 112(n)(4)(A) 
states

Notwithstanding the provisions of subsection (a), emissions from any 
oil or gas exploration or production well (with its associated 
equipment) and emissions from any pipeline compressor or pump 
station shall not be aggregated with emissions from other similar 
units, whether or not such units are in a contiguous area or under 
common control, to determine whether such units or stations are 
major sources, and in the case of any oil and gas exploration or 
production well (with its associated equipment), such emissions 
shall not be aggregated for any purpose under this section.

The language in section 112(n)(4)(A) makes it clear that, for the 
purpose of implementing standards for major sources under section 
112(d) for this industry, HAP emissions from oil and natural gas 
exploration and production wells with their associated equipment cannot 
be aggregated in making major source determinations.
    However, the statutory language provides no definition of 
``associated equipment.'' Neither is a clear intent evident in the 
legislative history of the Act's 1990 amendments. The legislative 
history does indicate that the Congress, in drafting section 112(n)(4), 
believed that wells and their associated equipment generally: (1) Have 
low HAP emissions, and (2) are typically located in widely dispersed 
geographic areas, rather than concentrated in a single area.
    A definition of associated equipment is important to implementing 
standards for this industry for two reasons. First, because the statute 
prevents the aggregation of HAP emissions from wells and their 
associated equipment in making major source determinations, the 
definition of associated equipment can influence which sources are 
subject to requirements for major sources and which are subject to 
requirements for area sources. Second, the definition of associated 
equipment affects the regulation of area sources in the oil and natural 
gas source category. Section 112(n)(4)(B) states


[[Page 6301]]


The Administrator shall not list oil and gas production wells (with 
its associated equipment) as an area source under subsection (c), 
except that the Administrator may establish an area source category 
for oil and gas production wells located in any metropolitan 
statistical area with a population in excess of 1 million, if the 
Administrator determines that emissions of hazardous air pollutants 
from such wells present more than a negligible risk of adverse 
effects to public health.

Thus, production wells (with their associated equipment) may not be 
regulated as an area source, but production wells as an individual area 
source may be regulated by the Administrator under section 112(n)(4)(B) 
upon an adverse risk determination.
    In the absence of clear guidance in the statute, the EPA considered 
options for defining associated equipment. In extensive discussions 
with industry and trade association representatives, the EPA evaluated 
a wide range of options.
    One option considered was a definition based on a narrow 
interpretation of associated equipment that would include only limited 
equipment in close proximity to a well as associated with that well. 
Another option considered was a definition based on a broad 
interpretation of associated equipment that would extend the inclusion 
of equipment far beyond the well as associated equipment. The initial 
options considered by the EPA for defining associated equipment and the 
EPA's assessment of each are discussed below.
    The narrowest interpretation option would be that a well and its 
associated equipment consists of only the well, defined as all 
equipment below the ground surface, and the pressure maintenance and 
flow control device attached to the well. For an exploratory well, the 
typical pressure maintenance and flow control device is the blow out 
preventer (BOP). For a production well, the typical pressure 
maintenance and flow control device is referred to as the ``Christmas 
tree,'' which may include a BOP. This interpretation would provide a 
technical meaning to the term associated equipment, but would provide 
limited substantive meaning.
    As a practical matter, the term ``well with its associated 
equipment'' under this option would not provide any additional relief 
to industry from the aggregation of HAP emissions in a major source 
determination beyond what would have been provided if Congress had only 
used the term ``well'' in section 112(n)(4) of the Act. On this basis, 
the EPA did not select this narrow interpretation for proposal.
    An option initially suggested by industry is that all production 
equipment be considered associated equipment. This is the broadest 
possible interpretation of the term associated equipment and would 
extend the definition to the boundaries of the source category, which 
are (1) to the point of custody transfer for hydrocarbon liquids and 
(2) to the natural gas transmission and storage source category for 
natural gas. Under this interpretation, industry maintains that no 
aggregation of HAP emissions should be allowed, even in situations 
commonly acknowledged to be a single facility. Only individual emission 
points which, by themselves, emit 10 tpy or more of any one HAP or 25 
tpy or more of any combination of HAP would be regulated as major 
sources under this interpretation.
    The EPA rejects this broad interpretation as an option for defining 
associated equipment for several reasons. First, an interpretation of 
the language in section 112(n)(4) that would define all equipment as 
associated with a well, regardless of (1) the type of equipment, (2) 
any processing or commingling of streams that may occur, or (3) 
distance from the well, would suggest that the Congress intended that 
aggregation of HAP emissions not be allowed within this industry under 
any circumstances. When viewed within the framework of section 112, the 
EPA does not believe this to be the case.
    For example, a natural gas processing plant has numerous HAP 
emission points closely grouped together. These points may include one 
or more glycol dehydration units, condensate storage vessels, several 
gas treatment and separation steps, and various containers. These HAP 
emission points may emit, in total, HAP in excess of 25 tpy. Each HAP 
emission point within the natural gas processing plant, however, may 
emit less than 10 tpy of any one HAP or 25 tpy of any combination of 
HAP.
    If all equipment within the plant were defined as associated 
equipment, then the plant would not be considered a major source 
subject to MACT standards. It is, therefore, conceivable that the 
natural gas processing plant that meets the criteria of a major source 
could go unregulated by MACT standards under this scenario, even though 
surrounding populations were exposed to HAP emissions at a level that 
would trigger the application of MACT standards in other similar 
industries.
    In addition, this option would include (as associated equipment) 
HAP emission points that the EPA has determined are large individual 
sources of HAP. In particular, available information indicates that 
glycol dehydration units and storage vessels emit substantial 
quantities of HAP.
    Glycol dehydration units are the largest identified HAP emission 
point in the oil and natural gas production source category, accounting 
for about 90 percent of estimated total HAP emissions from this source 
category based on available information used in the EPA's analysis. 
Individually, glycol dehydration units may emit total HAP in amounts 
from less than 0.9 Mg/yr to substantially above major source levels.
    Also, a single storage vessel with flash emissions may emit several 
megagrams of HAP per year.
    The EPA firmly believes that glycol dehydration units and storage 
vessels with flash emissions are not the type of small HAP emission 
points that Congress intended to be included in the definition of 
associated equipment. Further, as previously discussed in section V of 
this preamble, the EPA has made an area source finding that benzene 
emissions from TEG dehydration units pose a significant risk to public 
health.
    The EPA does not intend to regulate TEG dehydration units that emit 
small amounts of HAP. However, the EPA has an obligation to provide 
public health protection where there is risk from exposure to HAP 
emissions. If TEG dehydration units were included as associated 
equipment, the EPA's ability to provide protection to persons at risk 
from exposure would be severely limited through section 112(n)(4)(B).
    For all the reasons set out above, defining all equipment as 
associated equipment was rejected as an option for proposal by the EPA. 
However, the EPA believes that the use of custody transfer within an 
interpretation (along with other criteria) is a good method for 
delineating between equipment that is associated and not associated 
with a well.
    A variety of interpretations of associated equipment intermediate 
of those two extremes are also possible. Through discussions with 
industry and trade association representatives, the EPA considered 
several intermediate options based on drawing a line of demarcation 
downstream from the well. Equipment before this line of demarcation 
would be deemed to be associated with a well and equipment beyond the 
line would not be considered associated. The point in the processing of 
oil or natural gas at which such a line of demarcation could be drawn 
might be tied to where a certain product processing or transfer step 
takes place.

[[Page 6302]]

    Three intermediate options, using this approach, define associated 
equipment as including all equipment up to (1) the point where initial 
processing of an extracted hydrocarbon stream takes place, (2) the 
point of physical commingling of the extracted hydrocarbon stream with 
streams from other wells, and (3) the point of custody transfer, with 
exceptions for selected affected sources.
    The EPA evaluated each of these options with several objectives in 
mind. First, the option chosen should provide substantive meaning to 
the term associated equipment and prevent the aggregation of small, 
scattered HAP emission points in major source determinations. Second, 
the option chosen should be easily implementable. That is, it should be 
clear to the regulated community and enforcement personnel what is 
associated equipment and what is not associated equipment. Finally, the 
option chosen should not preclude the aggregation of the most 
significant HAP emission points in the source category. Additionally, 
the option chosen should not restrict the EPA's ability to regulate 
glycol dehydration units as area sources.
    An option tied to the point of initial processing would meet only 
the last of these objectives. Initial processing for many extracted 
hydrocarbon liquid and natural gas streams occurs immediately after the 
stream has left the well. Typical processing steps that may occur at a 
well site include gas/oil separation, heating/treating, and 
dehydration. The only equipment in addition to the Christmas tree that 
would be included as associated equipment under this option would be 
storage vessels in which no treating or separation takes place.
    Thus, little additional relief from HAP emission aggregation would 
be provided by an associated equipment definition based on initial 
processing. Also, the term ``point of initial processing'' is not a 
term commonly used and understood in the source category, a fact that 
would likely lead to confusion between enforcement agencies and the 
regulated community.
    Selecting an option based on the point of physical commingling of 
streams would provide additional substantive meaning to the term 
associated equipment and possible relief from HAP emission aggregation 
in situations where a stream from a single well undergoes processing 
prior to mixing with streams from other wells (the storage vessels and 
processing equipment would be associated with that well). However, the 
EPA sees great potential for confusion under this option, as the same 
equipment that would be considered associated equipment at a single 
well facility might not be associated equipment where streams from 
multiple wells are combined prior to processing.
    Another option is the use of the point of custody transfer in 
combination with allowing HAP emission aggregation for selected 
affected sources. For the proposed production regulation, the EPA 
defines custody transfer (which has been previously defined in other 
standards) as transfer, after processing and/or treatment in the 
producing operations, from storage vessels or automatic transfer 
facilities to pipelines or any other forms of transportation. The EPA 
considers the point at which natural gas enters a natural gas 
processing plant as a point of custody transfer for the proposed 
regulation.
    From an implementation perspective, this is an attractive option. 
According to industry and trade association representatives, the term 
custody transfer is commonly used and understood within the oil and 
natural gas production source category. Selecting this option would 
simplify the owner or operator's regulatory compliance determination 
for a specified piece of equipment. The point of custody transfer often 
denotes contractually the point of change in ownership of equipment or 
product. Therefore, defining associated equipment as all equipment up 
to the point of custody transfer is a good approach for delineating a 
line of demarcation between equipment that is associated and equipment 
that is not associated. This approach is the same as the broadest 
interpretation of associated equipment as initially proposed by 
industry, however, selected affected sources are not included as 
associated equipment.
    Glycol dehydration units and storage vessels with flash emissions 
are often located before the point of custody transfer. Many glycol 
dehydration units, for example, are located on single wells or at 
condensate tank batteries. As discussed previously, the EPA feels 
strongly that because glycol dehydration units and storage vessels with 
flash emissions are significant sources of HAP emissions, they are not 
the HAP emission points intended by Congress to be associated equipment 
under section 112(n)(4).
    Therefore, the EPA is proposing that associated equipment be 
defined as all equipment associated with a production well up to the 
point of custody transfer, except that glycol dehydration units and 
storage vessels with flash emissions would not be associated equipment. 
The EPA believes that this proposed definition will provide the relief 
that Congress intended in section 112(n)(4) while preserving the EPA's 
ability to require appropriate MACT or GACT controls for the most 
significant identified HAP emission points in the oil and natural gas 
production source category. The EPA considers the point at which 
natural gas enters a natural gas processing plant as a point of custody 
transfer for natural gas streams and HAP emission aggregation is 
allowed at natural gas processing plants. Natural gas processing plants 
are included in the scope of the oil and natural gas production NESHAP.

B. Definition of Facility

    As discussed in the previous section, it is not clear for many oil 
and gas field operations what constitutes a facility and, consequently, 
exactly where facility boundaries exist for the purpose of a major 
source determination. With many operations connected by pipeline and 
located on common oil and gas leases that extend for miles, the meaning 
of the phrase, ``located within a contiguous area under common 
control,'' used in section 112(a)(1) of the Act to describe sources 
that should be grouped in a major source determination, is not often 
clear when applied to oil and natural gas field operations. Relief from 
the possible need to aggregate emissions from certain small, widely 
dispersed, HAP emission sources is provided in the language of section 
112(n)(4), and in the EPA's proposed definition of associated 
equipment. However, potential for confusion still exists concerning 
when non-associated equipment should be aggregated. Thus, the EPA is 
proposing further clarification of what constitutes a facility for the 
purposes of major source determinations in the oil and natural gas 
production and natural gas transmission and storage source categories.
    The EPA's objective in developing a definition of facility for this 
proposed rulemaking is to identify criteria that would define a 
grouping of emission points that meet the intent of the section 
112(a)(1) language, ``located within a contiguous area and under common 
control,'' but in terms that are meaningful and easily understood 
within the regulated industries. Examples of general facility types in 
the oil and natural gas production source category include natural gas 
processing plants, offshore production platforms, central tank 
batteries, satellite tank batteries, and individual well sites. 
Compressor stations and underground storage facilities are examples of

[[Page 6303]]

facilities in the natural gas transmission and storage source category.
    Though some facilities in the oil and natural gas production source 
category, such as natural gas processing plants, fit the profile of a 
typical industrial facility and are easy to define, other facilities 
(e.g., production field facilities) do not fit the typical profile. 
Substantial differences exist between the majority of typical oil and 
natural production field operations and traditional industrial 
facilities that are regulated under the Act. Industrial facilities 
typically have distinct physical boundaries or fencelines. Emission 
points at these facilities are generally in close proximity to or 
collocated with one another (contiguous) and located within an area 
boundary, the entirety of which (other than roads, railroads, etc.) is 
under the physical control of the same owner (common ownership).
    Typical oil and natural gas production field facilities do not 
adhere to this profile. The owners or operators of production field 
facilities typically do not own or control the surface property that 
lies between two or more production field facilities. Rather, the 
owners or operators of production field facilities control only the 
surface area that is necessary to operate the physical structures used 
in oil and natural gas production. Production facilities may be 
connected by underground flow or gathering lines but are essentially 
separate independent facilities. Production equipment sharing the same 
close physical location (e.g., a well site, tank battery, or graded 
pad) is likely to be under common control and in a contiguous area. 
However, production equipment that is physically separated within or 
across leases (to serve different wells and connected by flow or 
gathering lines) is not contiguous based on surface rights and is not 
likely to be under common control.
    The EPA intends that a facility definition as it applies to the oil 
and natural gas production source category should lead to an 
aggregation of emissions in a major source determination that is 
reasonable, consistent with the intent of the Act, and easily 
implementable. In this source category, functionally related equipment 
is generally located at what is referred to as the same surface site. 
Surface site means the graded pad, gravel pad, foundation, platform, or 
immediate physical location on which equipment is located. Defining 
facility based on individual surface site would, in the EPA's view, 
identify groupings of equipment on which major source determinations 
would be made that are consistent with the EPA's intent. For example, a 
definition on this basis would require aggregation of emissions from 
significant HAP emission sources that are closely grouped, such as two 
or more glycol dehydration units on the same graded pad treating a 
natural gas stream. Glycol dehydration units located on different 
graded pads, for example at separate tank batteries, would presumably 
not be functionally related (i.e., the units treat different streams) 
and in most cases would be separated by considerable distance. 
Consequently, the EPA does not believe it would be reasonable to 
combine emissions from these units. Finally, because the term surface 
site is well understood within industry and easily recognizable by 
enforcement authorities, a facility definition on this basis should be 
easily implementable. For these reasons, the EPA is proposing a 
facility definition based on individual surface site. For further 
clarification, the EPA is also proposing that equipment located on 
different oil and gas properties (oil and gas lease, mineral fee tract, 
subsurface unit area, surface fee tract, or surface lease track) shall 
not be aggregated.
    Another objective of the EPA in developing a definition of facility 
was to minimize, where possible and reasonable, the burden on owners 
and operators in making a major source determination. The EPA's 
evaluation of HAP emission sources in production field operations 
indicates that the two primary HAP emission points at field operation 
facilities are glycol dehydration units and storage tanks with flash 
emissions, and that other potential HAP emission points at these 
facilities (e.g., equipment leaks) will be inconsequential to the 
determination of a facility's major source status. Therefore, the EPA 
is proposing that for the purpose of a major source determination, a 
production field facility would be limited to glycol dehydration units 
and storage tanks with flash emission potential. The EPA believes that 
by eliminating the need to quantify HAP emissions from small sources at 
such facilities, the burden on an owner or operator to make a major 
source determination would be greatly reduced, while still ensuring an 
accurate classification of the facility as a major or area source of 
HAP emissions.
    The EPA specifically requests comments on the proposed definition 
of facility. Specifically the EPA requests comments on whether the 
proposed definition appropriately implements the intent of the major 
source definition in section 112(a)(1) for the oil and natural gas 
production and natural gas transmission and storage source categories, 
or if another definition would better implement this intent.

VIII. Rationale for Proposed Standards

A. Selection of Hazardous Air Pollutants for Control

    The EPA believes that it is not appropriate to select all organic 
HAP listed under section 112(b) of the Act for regulation under the 
proposed NESHAP. Of the 188 compounds listed, only a limited number are 
emitted from oil and natural gas facilities. Consequently, the EPA 
developed a list of the specific HAP to be regulated in the proposed 
rules. However, all 188 listed HAP must be considered in any major 
source determination under the General Provisions to 40 CFR Part 63.
    To select which HAP are to be regulated under the proposed NESHAP, 
the EPA evaluated the potential for HAP to be emitted from oil and 
natural gas facilities. Based on this evaluation, the EPA is proposing 
that the following specific HAP be regulated under the proposed NESHAP: 
acetaldehyde, benzene (including benzene in gasoline), carbon 
disulfide, carbonyl sulfide, ethyl benzene, ethylene glycol, 
formaldehyde, n-hexane, naphthalene, toluene, 2,2,4-trimethylpentane 
(iso-octane), and mixed xylenes, including o-xylene, m-xylene, and p-
xylene.
    The EPA decided to develop a set of control options for this 
industry to control HAP emissions as a class rather than developing a 
series of control options to control emissions of each individual HAP 
on the list. Consequently, the control options considered are directed 
towards the control of total HAP emissions.

B. Selection of Emission Points

    The EPA identified the primary types of HAP emission points at oil 
and natural gas facilities. The three primary HAP emission point types 
are (1) process vents, (2) storage vessels, and (3) equipment leaks.
    The primary process vent HAP emission point is the glycol 
dehydration unit reboiler vent. A glycol dehydration unit reboiler 
regenerates glycol used in the dehydration of natural gas by separating 
the water from the glycol. The glycol also attracts aromatic compounds, 
including BTEX and n-hexane during the dehydration process. These HAP, 
along with the water vapor and other gases, are emitted through the 
glycol dehydration unit reboiler vent.
    In addition, glycol dehydration units may incorporate the use of a 
gas condensate glycol separator (GCG separator or flash tank). The rich 
glycol,

[[Page 6304]]

which has absorbed water vapor from the natural gas stream, leaves the 
bottom of the absorption column of a glycol dehydration unit and is 
directed either to (1) GCG separator (flash tank) and then a reboiler 
or (2) directly to a reboiler where the water is boiled off the rich 
glycol. If the system includes a GCG separator (flash tank), the gas 
separated from the rich glycol is typically (1) recycled to the header 
system, (2) used for fuel, or (3) used as a stripping gas. The GCG 
separator (flash tank) vent is a potential HAP emission point if vented 
to the atmosphere.
    Other potential HAP emission point process vents are the tail gas 
streams from amine treating processes and sulfur recovery units. 
Limited data have been identified that indicate the potential for HAP 
emissions from these operations. Thus, HAP emissions from amine 
treating processes and sulfur recovery units have not been estimated. 
Recent research published by GRI indicates that these emission points 
have the potential to be significant sources of HAP emissions. Comment 
is requested on potential HAP emissions and emission rates from these 
operations and potential applicable air emission controls.
    Storage vessels have also been identified as a HAP emission point. 
Storage vessels used in the oil and natural gas industry include 
storage vessels with flash emissions. Storage vessels in the oil and 
natural gas production source category are commonly equipped with fixed 
roofs. Emissions from fixed-roof storage vessels with flash emissions 
are a result of breathing, working, and (primarily) flash losses.
    Pipeline pigging and storage of pipeline pigging wastes is a 
potential HAP emission point in the transmission sector of the oil and 
natural gas industry. Only limited qualitative data have been 
identified that indicate the potential for HAP emissions from this 
operation. Thus, HAP emissions have not been estimated. Comment is 
requested on potential HAP emissions from storage of pipeline pigging 
wastes and potential applicable emission controls.
    Valves, pump seals, and other pieces of equipment servicing HAP-
containing streams have the potential to leak. A majority of facilities 
in the oil and natural gas industry do not have LDAR programs. 
Therefore, equipment leaks from that equipment servicing HAP-containing 
streams have been identified as a potential HAP emission point.
    In addition to the above HAP emission points, the EPA evaluated the 
potential regulation of other HAP emission points. These included (1) 
containers, (2) equipment leaks at tank batteries and offshore 
production platforms, (3) production surface impoundments, and (4) 
waste and wastewater management units.
    Insufficient data were submitted in the Air Emissions Survey 
Questionnaire responses for the other potential HAP emission points of 
containers, equipment leaks at tank batteries and offshore production 
platforms, production surface impoundments, and waste and wastewater 
management units to allow for determination of existing control levels. 
Thus, a review of other data sources was conducted to identify 
information on existing control levels for these potential HAP emission 
points.
    For these other HAP emission points, the review of available 
information did not indicate any apparent pattern of existing emission 
controls. Thus, it has been determined that the existing level of 
control for this collection of other HAP emission points is no control.

C. Definition of Affected Source

    The term affected source is used in part 63 regulations to 
designate the emission sources or group of sources that are regulated 
by a standard. Each standard must define what the affected source is 
for purposes of that specific standard.
    The EPA has discretion to establish a narrow or broad definition of 
affected source, as appropriate for a particular rule. A broad 
definition would be in terms of groups of equipment. A narrow 
definition would designate specific pieces of equipment or emission 
points as separate affected sources.
    For the proposed oil and natural gas production and natural gas 
transmission and storage NESHAPs, a narrow definition of affected 
source is proposed for most HAP emission points. The affected sources 
under the oil and natural gas production NESHAP include (1) each glycol 
dehydration unit located at a major source of HAP, (2) each TEG 
dehydration unit located at an area source of HAP, and (3) each storage 
vessel with flash emissions located at a major source of HAP.
    For the proposed standards for equipment leaks at natural gas 
processing plants, the EPA is proposing a broad definition of affected 
source. Specifically, the group of equipment targeted by fugitive 
emission standards (pumps, pressure relief devices, valves, flanges, 
etc. that operate in organic HAP service) are designated as one 
affected source, except that compressors would each be a separate 
affected source. The implication of this broader definition is that the 
replacement of an individual component, such as a valve, would not be 
considered the construction of a new affected source, which triggers 
reporting requirements for new sources.
    The affected source under the natural gas transmission and storage 
NESHAP is each glycol dehydration unit located at a major source of 
HAP.

D. Determination of MACT Floor

    As described in this preamble, the Act defines a minimum level of 
control for standards established under section 112(d), referred to as 
the MACT floor. For a source category with 30 or more sources, such as 
with the oil and natural gas production and natural gas transmission 
and storage source categories, the MACT floor for existing sources 
shall not be less stringent than the average emission limitation 
achieved in practice by the best performing 12 percent of existing 
sources. Standards more stringent than the floor may be established 
based on a consideration of cost, environmental, energy, and other 
impacts.
    The EPA is to establish standards based on available information. 
Available information for the MACT floor analysis for these source 
categories consists primarily of data gathered from industry responses 
to survey questionnaires. The surveys were designed to collect 
information representative of processes and operations in these source 
categories.
1. MACT Floor for Existing Sources
    Oil and Natural Gas Production-Glycol Dehydration Unit Vents; 
Natural Gas Transmission and Storage-Glycol Dehydration Unit Vents. The 
MACT floor for all process vents at glycol dehydration units (including 
area source TEG dehydration units in the oil and natural gas production 
source category) is 95 percent HAP emission reduction, which correlates 
with the existing control level estimated to be achieved through the 
use of condensers.
    Oil and Natural Gas Production-Storage Vessels. The MACT floor for 
existing storage vessels containing material with a GOR equal to or 
greater than 50 m \3\ (1,750 ft \3\) per barrel or an API gravity equal 
to or greater than 40 deg. and an actual throughput equal to or greater 
than 500 BPD (i.e., storage vessel with flash emissions) is the 
installation and operation of a cover that is connected through a 
closed-vent system to a 95 percent efficient control device. A 
pressurized storage vessel that is designed to operate as a closed 
system is considered in compliance with the requirements for storage 
vessels.

[[Page 6305]]

    Oil and Natural Gas Production-Equipment Leaks. The MACT floor 
levels for equipment leaks apply only to those components at natural 
gas processing plants handling material with a total HAP content equal 
to or greater than 10 percent by weight.
    The MACT floor for equipment leaks at natural gas processing plants 
is judged to be at the new source performance standard (NSPS) level of 
control for natural gas processing plants. The NSPS level of control is 
equal to that of 40 CFR part 61, subpart V (equipment leaks NESHAP). 
Since the pollutants targeted for control under the proposed standards 
are HAP, the proposed standards cross-reference the requirements from 
the equipment leaks NESHAP.
    The proposed standards require monthly monitoring of equipment with 
a leak definition of 10,000 ppmv VOC. Based on the component counts and 
other characteristics of the model natural gas processing plants, it is 
estimated that the NESHAP LDAR program would attain a 70 percent HAP 
emission reduction from uncontrolled cases. The proposed standards 
allow existing natural gas processing plants subject to the NSPS to 
comply only with those requirements.
2. MACT Floor for New Sources
    In the review of available information, the EPA did not identify a 
method of control applicable to all types of new sources that would 
achieve a greater level of HAP emission reduction than the MACT floor 
for existing sources. Therefore, the MACT floor for new sources in the 
oil and natural gas production and natural gas transmission and storage 
source categories is the same as the MACT floor for existing sources.

E. Oil and Natural Gas Production NESHAP-Regulatory Alternatives for 
Existing and New Major Sources

    The EPA evaluated two regulatory alternatives for existing and new 
major sources in the oil and natural gas production source category. 
The first regulatory alternative is the MACT floor levels for the 
identified HAP emission points. A second regulatory alternative was 
evaluated that included the installation of combustion control systems 
for process vents and storage tanks at all impacted major sources. 
Combustion systems typically have a control efficiency of 98 percent, 
or greater, as compared with the control systems in Regulatory 
Alternative 1, which achieve an emission reduction efficiency of 95 
percent.
    Regulatory Alternative 1 (MACT floor) would achieve a nationwide 
decrease in HAP emissions from all HAP emission points at major sources 
of approximately 77 percent. In the EPA's judgement, the costs (and the 
associated cost-effectiveness) of going beyond the floor would be 
greatly disproportional to the additional HAP emission reduction that 
would be achieved. The costs and average and incremental cost-
effectiveness of the two regulatory alternatives are presented in Table 
4. Based on this and other information, the EPA selected Regulatory 
Alternative 1 (MACT floor) as the basis for the proposed standards. In 
addition, the EPA did not select Regulatory Alternative 2 since the 
control options evaluated (combustion systems) involved the destruction 
of a recoverable non-renewable resource and did not encourage the 
application of pollution prevention techniques.

   Table 4.--Comparison of Regulatory Alternative Cost Impacts for the  
     Proposed Oil and Natural Gas Production Standards--Major Source    
                               Provisions                               
------------------------------------------------------------------------
                                              Regulatory alternative    
             Cost category              --------------------------------
                                         1  (MACT floor)         2      
------------------------------------------------------------------------
Implementation costs (Million of July                                   
 1993 $):                                                               
    Total installed capital............              6.5              18
    Total annual.......................              4.0              23
Cost-effectiveness ($/Megagram HAP):                                    
    Average............................            130               740
    Incremental........................  ...............          19,000
------------------------------------------------------------------------

    These standards would impact those glycol dehydration units, at 
major sources, with an actual natural gas throughput equal to or 
greater than 85 thousand m\3\/day (3.0 MMSCF/D), on an annual average 
basis, unless it is demonstrated that benzene emissions from the unit 
were less than 0.9 Mg/yr (1 tpy).

F. Oil and Natural Gas Production NESHAP-Regulatory Alternatives for 
Existing and New Area Sources

    The EPA evaluated four regulatory alternatives for TEG dehydration 
units at existing and new area sources at oil and natural gas 
production sources. Each regulatory alternative is characterized in 
terms of an action level, above which HAP emissions must be controlled. 
The action levels considered are expressed as the actual annual average 
flow rate of natural gas (in thousand m\3\/day (MMSCF/D)) to the TEG 
dehydration unit. The action levels for the regulatory alternatives are 
(1) 113 thousand m\3\/day (4.0 MMSCF/D) or greater, (2) 85 thousand 
m\3\/day (3.0 MMSCF/D) or greater, (3) 42 thousand m\3\/day (1.5 MMSCF/
D) or greater, and (4) 8.5 thousand m\3\/day (0.3 MMSCF/D) or greater.
    Based on an evaluation of the projected action level impacts and 
costs-effectiveness, the EPA selected Regulatory Alternative 2 as 
representative of GACT for TEG dehydration units at area sources of 
HAP. Alternative 2 would impact those TEG dehydration units with an 
actual natural gas throughput equal to or greater than 85 thousand 
m\3\/day (3.0 MMSCF/D), on an annual average basis, unless it is 
demonstrated that benzene emissions from the unit were less than 0.9 
Mg/yr (1 tpy).
    It is the objective of the EPA to structure the rules for area 
sources in a way that protects exposed populations. The EPA also needs 
to minimize the cost to industry to control units where there would be 
less human exposure and overall cancer incidence from exposure to HAP 
emissions from area source TEG dehydration units.
    Therefore, the EPA is proposing a criterion that no unit would have 
to be controlled if it is demonstrated that emissions of benzene from 
the unit are less than 0.9 Mg/yr (1 tpy), either uncontrolled or with 
controls in place under federally enforceable limits. As noted 
previously, benzene is a known human carcinogen that is typically 
emitted from TEG dehydration units.

[[Page 6306]]

    The EPA is also proposing the use of a population-based action 
level in conjunction with the actual natural gas throughput and benzene 
emission rate action levels for area source TEG dehydration units. The 
EPA selected an action level based on the county-level urban versus 
rural location of area source TEG dehydration units. Only those 
selected area source TEG dehydration units located in counties 
classified as urban (see section III of this preamble) and also meeting 
or exceeding the actual natural gas throughput and benzene emission 
rate action levels will be required to install air emission controls on 
all process vents.

G. Natural Gas and Transmission NESHAP-Regulatory Alternatives for 
Existing and New Major Sources

    The EPA evaluated two regulatory alternatives for existing and new 
major sources in the natural gas transmission and storage source 
category. The first regulatory alternative is the MACT floor level for 
all process vents at glycol dehydration units. A second regulatory 
alternative was evaluated that included the installation of combustion 
control systems for process vents at all impacted major sources. 
Combustion systems typically have a control efficiency of 98 percent, 
or greater, as compared with the control systems in Regulatory 
Alternative 1 which achieve an emission reduction efficiency of 95 
percent.
    Regulatory Alternative 1 (MACT floor) would achieve a nationwide 
decrease in HAP emissions from major sources of approximately 95 
percent. The costs and the associated cost-effectiveness of going 
beyond the floor would be greatly disproportional to the additional HAP 
emission reduction that would be achieved. The costs and average and 
incremental cost-effectiveness of the two regulatory alternatives are 
presented in Table 5. Based on this and other information, the EPA 
selected Regulatory Alternative 1 (MACT floor) as the basis for the 
proposed standards. In addition, the EPA did not select Regulatory 
Alternative 2 since the control options evaluated (combustion systems) 
involved the destruction of a recoverable non-renewable resource and 
did not encourage the application of pollution prevention techniques.

   Table 5.--Comparison of Regulatory Alternative Cost Impacts for the  
         Proposed Natural Gas Transmission and Storage Standards        
------------------------------------------------------------------------
                                              Regulatory alternative    
              Cost category              -------------------------------
                                          1 (MACT floor)         2      
------------------------------------------------------------------------
Implementation costs (Thousand of July                                  
 1993 $):                                                               
    Total installed capital.............              57             230
Total annual                                          46             250
Cost-effectiveness ($/Megagram HAP):                                    
    Average.............................             420           2,100
    Incremental.........................  ..............          20,000
------------------------------------------------------------------------

H. Selection of Format

    Section 112(d) of the Act requires that emission standards for 
control of HAP be prescribed unless, in the judgement of the 
Administrator, it is not feasible to prescribe or enforce emission 
standards. Section 112(h) identifies two conditions under which it is 
not considered feasible to prescribe or enforce emission standards. 
These conditions include (1) if the HAP cannot be emitted through a 
conveyance device or (2) if the application of measurement methodology 
to a particular class of sources is not practicable due to 
technological or economic limitations. If emission standards are not 
feasible to prescribe or enforce, then the Administrator may instead 
promulgate equipment, work practice, design or operational standards, 
or a combination thereof.
    Formats for emission standards include (1) percent reduction, (2) 
concentration limits, or (3) a mass emission limit. For the proposed 
NESHAPs, standards solely expressed as a percent, concentration, or 
mass emission reduction would not alone appropriately reflect the 
technologies on which the proposed standards are based and ensure that 
the intended emissions reductions are achieved. Therefore, the proposed 
standards are a combination of (1) emission standards and (2) 
equipment, design, work practice, and operational standards.
    The format chosen for glycol dehydration unit (including area 
source TEG dehydration units subject to the proposed oil and natural 
gas production NESHAP) process vent streams is a HAP weight-percent 
reduction requirement that applies to the control device. A weight-
percent reduction format is appropriate for streams with HAP 
concentrations above 1,000 ppmv because such a format ensures the 95 
percent control level requirement. The format for the proposed storage 
vessel provisions is a combination of a weight-percent reduction and 
inspection, repair, and work practice requirements. The inspection, 
repair, and work practice requirements are necessary to ensure the 
proper operation and integrity of control equipment.
    For equipment leak sources, such as pumps and valves, the EPA has 
previously determined that it is not feasible to prescribe or enforce 
emission standards. Except for those items of equipment for which 
standards can be set at a specific concentration. The only method of 
measuring emissions is total enclosure of individual items of 
equipment, collection of emissions for a specified time period, and 
measurement of the emissions. This procedure, known as bagging, is a 
time-consuming and prohibitively expensive technique considering the 
great number of individual items of equipment in a typical process 
unit.
    The proposed standards for equipment leaks at natural gas 
processing plants incorporate several formats, including equipment, 
design, base performance levels, work practices, and operational 
practices. The proposed formats are the same as for the natural gas 
processing plant (on-shore) NSPS and the 40 CFR part 61, subpart V 
equipment leaks (fugitive emissions) NESHAP.

I. Selection of Test Methods and Procedures

    Test methods and procedures specified in the proposed standards

[[Page 6307]]

would be used to demonstrate compliance. Procedures and methods 
included in the proposed standards are, where appropriate, based on 
procedures and methods previously developed by the EPA for use in 
implementing standards for sources similar to those being proposed for 
regulation. Methods and procedures are included to determine the 
following (1) no detectable emissions, (2) volatile organic HAP (VOHAP) 
concentration, (3) control device performance (i.e., control-
efficiency), and (4) annual average flow rate of field natural gas to a 
glycol dehydration unit.

J. Selection of Monitoring and Inspection Requirements

    Control devices used to comply with the proposed standards need to 
be properly operated and maintained if the standards are to be achieved 
on a long-term basis. The EPA considered two monitoring options for 
these NESHAPs (1) the use of CMS and (2) the use of monitors that 
measure operating parameters that can be directly related to the 
emission control performance of a particular control device.
    The CMS that use gas chromatography to measure individual gaseous 
organic HAP compound chemicals are not practical for applications where 
multiple organic HAP chemicals are to be monitored, as is typical with 
oil and natural gas production and natural gas transmission and storage 
facilities.
    An alternative is to use a CMS to measure total VOC or total 
hydrocarbons (THC) as a surrogate for total organic HAP. These CMS, 
however, provide a measure of the relative concentration level of a 
mixture of organic chemicals, rather than a quantified level of the 
organic species present.
    Based on these reasons, the EPA rejected requiring the use of CMS 
for the proposed NESHAPs. Instead, the EPA selected monitoring of 
control device operating parameters indicative of air emission control 
performance as the appropriate approach to monitoring.
    The proposed NESHAPs specify the types of parameters that can be 
monitored for common types of control devices. These parameters were 
selected because they are good indicators of control device performance 
and because continuous parameter monitoring instrumentation is 
available at a reasonable cost. An owner or operator could be approved, 
on a case-by-case basis, to monitor parameters not specifically listed 
in the proposed standards.
    The established operating parameters for each control device will 
be incorporated in the operating permit issued for a facility (or, in 
the absence of an operating permit, the established levels will be 
directly enforceable) and will be used to determine a facility's 
compliance status. Excursions outside the established operating 
parameter values will be considered violations of the applicable 
emission standards, except when the excursion is caused by a startup, 
shutdown, or malfunction that meets the criteria specified in the part 
63 General Provisions (40 CFR part 63 subpart A).
    Continuous monitoring is not feasible for those emission points 
required to comply with certain equipment standards and work practice 
standards (e.g., storage vessels equipped with only covers, pumps and 
valves subject to LDAR programs). In such cases, failure to install and 
maintain the required equipment or properly implement the LDAR program 
constitutes a violation of the applicable equipment or work practice 
standards.
    The owner or operator of a glycol dehydration unit that does not 
install controls would be required to install a flow monitor to 
demonstrate that the actual natural gas flow rate to the unit is less 
than the action level of 85 thousand m\3\/day (3.0 MMSCF/D), on an 
annual average basis. If a flow monitor is installed, it must have an 
accuracy of within 2 percent.

K. Selection of Recordkeeping and Reporting Requirements

    The EPA may require an owner or operator of a source to establish 
and maintain records and prepare and submit notifications and reports. 
General recordkeeping and reporting requirements for all NESHAP are 
specified in the part 63 General Provisions (40 CFR 63.9 and 40 CFR 
63.10).
    The proposed standards would require sources to submit (1) initial 
notification reports, (2) notification of compliance status reports, 
and (3) other periodic reports (e.g., startup, shutdown and malfunction 
report, excess emissions report, CMS performance test report).
    All recordkeeping and reporting requirements proposed for major 
sources are consistent with the General Provision requirements, except 
that (1) the initial notification would not be due for a year and (2) 
the startup, shutdown and malfunction report, excess emissions report, 
and CMS performance test report would be required semi-annually rather 
than quarterly unless otherwise specified by the State regulatory 
authority.
    The EPA is proposing fewer recordkeeping and reporting requirements 
for oil and natural gas production area sources. Specifically, the 
owners and operators of applicable area sources are not subject to (1) 
the requirements in Sec. 63.6, paragraph (e) of the General Provisions 
for developing and maintaining a startup, shutdown, and malfunction 
plan or (2) the requirements in Sec. 63.10, paragraph (d) for reporting 
actions consistent with the plan. The owners and operators of 
applicable area sources are required to submit a report identifying 
occurrences of startup, shutdown, or malfunction when these events 
happen or are anticipated to happen.
    Further, the periodic excess emissions reports and summary reports, 
as described in Sec. 63.10 paragraph (e)(3) of the General Provisions, 
are required on a less frequent basis than for major sources. For area 
sources, these reports are required annually (i.e., major sources need 
to submit these reports semi-annually). This was done to reduce the 
recordkeeping and reporting burden on owners and operators of affected 
facilities.

IX. Relationship to Other Standards and Programs under the Act

A. Relationship to the Part 70 and Part 71 Permit Programs

    Under title V of the Act, the EPA established a permitting program 
(part 70 and part 71 permitting program) that requires all owners and 
operators of HAP-emitting sources to obtain an operating permit (57 FR 
32251, July 21, 1992). Sources subject to the permitting program (i.e., 
oil and natural gas production and natural gas transmission and storage 
sources) are required to submit complete permit applications within a 
year after a State program is approved by the EPA or, where a State 
program is not approved, within a year after a program is promulgated 
by the EPA. If the State where the facility is located does not have an 
approved permitting program, the owner or operator of a facility must 
submit the application to the EPA Regional Office in accordance with 
the requirements of the part 63 General Provisions (40 CFR 63 subpart 
A).
    In addition, section 502(a) of the Act expressly gives the 
Administrator the discretion to exempt one or more area source 
categories (in whole or in part) from the requirement to obtain a 
permit under 42 U.S.C. 7661a(a).

* * * if the Administrator finds that compliance with such 
requirements is impracticable, infeasible, or unnecessarily 
burdensome on such categories.


[[Page 6308]]


One critical factor that the EPA considers as part of the 
``unnecessarily burdensome'' criteria is the degree to which the 
standard is implementable outside of a permit, such that the permit 
would provide minimal additional benefit with regard to source-specific 
tailoring of the standards.
    All area source TEG dehydration units impacted by the provisions of 
the proposed standards must (1) comply with the compliance schedule 
within the rule, (2) perform monitoring of the required parameters for 
ensuring compliance, and (3) follow the limited recordkeeping and 
reporting requirements. Therefore, the primary goal of significant 
reductions in HAP emissions, particularly BTEX and n-hexane, would be 
achieved, regardless of whether a permit is required. Unless otherwise 
required by the State, the owner or operator of an area source subject 
to the proposed standards is not required to obtain a permit under part 
70 of title 40 CFR.

B. Relationship Between the Oil and Natural Gas Production and the 
Organic Liquids Distribution (Non-Gasoline) Source Categories

    The EPA believes that a clear applicability demarcation is 
necessary to distinguish those sources that would be subject to the 
proposed oil and natural gas production NESHAP and those that would be 
subject to the organic liquids distribution (non-gasoline) NESHAP, 
which is scheduled for promulgation by the year 2000.
    The proposed standards for the oil and natural gas production 
source category identify the source category and applicability as 
including facilities up to the point of custody transfer. The EPA 
intends to define the organic liquids distribution (non-gasoline) 
source category as including those facilities that handle and 
distribute organic liquids (non-gasoline) from the point of custody 
transfer.

C. Relationship of Proposed Standards to the Pollution Prevention Act

    The Congress passed and the President signed into law the Pollution 
Prevention Act of 1990 (PPA) making pollution prevention a national 
policy. Section 6602(b) identifies an environmental management 
hierarchy in which pollution

* * * should be prevented or reduced whenever feasible; pollution 
that cannot be prevented should be recycled in an environmentally 
safe manner, whenever feasible; pollution that cannot be prevented 
or recycled should be treated in an environmentally safe manner, 
whenever feasible; and disposal or other releases into the 
environment should be employed only as a last resort * * *

In short, preventing pollution before it is created is preferable to 
trying to manage, treat or dispose of it after it is created.
    According to PPA section 6603, source reduction is defined as 
reducing the generation and release of hazardous substances, 
pollutants, wastes, contaminants or residuals at the source, usually 
within a process. The term includes equipment or technology 
modifications, process or procedure modifications, reformulation or 
redesign of products, substitution of raw materials, and improvements 
in housekeeping, maintenance, training, or inventory control. Source 
reduction does not include any practice that alters the physical, 
chemical, or biological characteristics or the volume of a hazardous 
substance, pollutant, or contaminant through a process or activity that 
is not integral to or necessary for producing a product or providing a 
service.
    Pertaining to these proposals, section 6604(b)(2) of the PPA 
directs the EPA to, among other things,

* * * review regulations of the Agency prior and subsequent to their 
proposal to determine their effect on source reduction.

The EPA believes that these proposed standards are consistent with the 
purpose of the Clean Air Act's requirement to consider source reduction 
technologies. The EPA's emphasis on source reduction hierarchy is also 
entirely consistent with the Act, particularly the air toxics provision 
(section 112) that requires the maximum achievable emission reductions 
through measures that

* * * reduce the volume of, or eliminate emissions of, such 
pollutants through process changes, substitution of materials or 
other modifications; * * *

In the proposed standards, the EPA has incorporated the application of 
the environmental source reduction management hierarchy. These proposed 
standards encourage source reduction by (1) control of HAP air 
emissions through the use of condensers and vapor collection/recovery 
systems and (2) allowing for the use of system optimization on glycol 
dehydration units through the adjustment of the glycol circulation 
rate. This adjustment may significantly reduce related HAP emissions 
because, on average, the glycol circulation rate is double the 
necessary rate.

D. Relationship of Proposed Standards to the Natural Gas STAR Program

    The Natural Gas STAR Program is a voluntary, cooperative program 
between the EPA and the natural gas industry to promote cost-effective 
methods for reducing methane emissions. The program, part of the U.S. 
Climate Change Action Plan, outlines a set of initiatives that will 
enable the profitable reduction of greenhouse gas emissions. The first 
phase of the program was initiated in 1993 with companies in the 
natural gas transmission and distribution industry. The 38 partner 
companies are currently capturing 36.8 million m\3\ (1.3 billion ft\3\ 
(bcf)) of methane annually, worth almost $3 million.
    The natural gas production industry program was initiated in 1995. 
When fully implemented in the year 2000, Natural Gas STAR companies are 
projected to recover more than 710 million m\3\ (25 bcf) of methane 
annually, worth an estimated $50 million.
    Under this program, partners agree to implement two best management 
practices (BMPs) when cost-effective. These include (1) identifying and 
replacing high-bleed pneumatic devices and (2) installing GCG 
separators (flash tank separators) on glycol dehydration units and 
recovering the separated methane stream. Additionally, the EPA has 
agreed to assist partner companies in the removal of unjustified 
regulatory barriers to implementing these practices.
    The standards proposed for the oil and natural gas production and 
natural gas transmission and storage source categories do not create 
regulatory barriers to implementing the BMPs encouraged under this 
program. The control requirements for glycol dehydration units at major 
sources and selected area sources would require control of the flash 
tank separator vent, if present. This would encourage further product 
recovery and reduction of HAP and methane air emissions and enhance the 
product recovery and emission reduction goals of the Natural Gas STAR 
Program.

E. Overlapping Regulations

    The proposed standards clarify the applicability of 40 CFR part 63, 
subpart HH (oil and natural gas production NESHAP) equipment leak 
provisions by stating that existing oil and natural gas production 
sources subject to subpart HH and 40 CFR part 60, subpart KKK (onshore 
natural gas processing plants NSPS) are required only to comply with 
subpart KKK.

[[Page 6309]]

X. Solicitation of Comments

    Comments are specifically requested on several aspects of the 
proposed standards. These topics are summarized below.

A. Potential-to-Emit

    The EPA is currently in the process of developing a separate 
rulemaking to address several potential-to-emit (PTE) issues. Until the 
EPA takes final action on the proposal, any determination of PTE made 
to determine a facility's applicability status under a relevant part 63 
standard should be made according to requirements set forth in the 
relevant standard and in the General Provisions.
    Industry representatives have commented that both oil and natural 
gas production and natural gas transmission and storage facilities 
often have a maximum capacity (based on physical and operational 
design) to emit higher than inherent physical limitations would allow. 
Concern was expressed that potential emissions could be overestimated 
and a facility could be subject to the Act requirements affecting major 
sources despite inherent limitations (e.g., depletion of oil and 
natural gas reservoirs).
    The EPA is committed to providing technical assistance on the type 
of inherent physical and operational design features that may be 
considered acceptable in determining the PTE for certain source 
categories. Therefore, the EPA is evaluating and solicits specific 
recommendations, along with supporting documentation, on how inherent 
limitations should be addressed for oil and natural gas production and 
natural gas transmission and storage facilities.

B. Definition of Facility

    The EPA specifically requests comments on the proposed definition 
of facility. Specifically, the EPA requests comments on whether the 
proposed definition appropriately implements the intent of the major 
source definition in section 112(a)(1) for the oil and natural gas 
production and natural gas transmission and storage source categories, 
or if another definition would better implement this intent.

C. Interpretation of ``Associated Equipment'' in Section 112(n)(4) of 
the Act

    As discussed in section V of this preamble, the EPA has proposed a 
definition for the term ``associated equipment'' to implement the 
special provisions of section 112(n)(4) of the Act for the oil and 
natural gas production source category. Comments are specifically 
requested on the EPA's proposed definition.
    If there is disagreement with the EPA's proposed definition, the 
EPA requests that the commenter provide alternative definition options, 
along with supporting documentation, that would provide the relief 
intended by Congress for this industry while preserving the EPA's 
ability to regulate HAP emissions from glycol dehydration units, 
storage vessels with flash emissions, and equipment leaks.

D. Regulation of Area Source Glycol Dehydration Units

    The EPA does not intend to regulate TEG dehydration units that have 
low HAP emissions or units in areas where there is little or no 
potential threat of adverse health effects from exposure to HAP 
emissions from TEG dehydration units. The rules, as proposed, include 
applicability cutoffs of (1) 85 thousand m\3\/day (3.0 MMSCF/D) of flow 
to the unit, on an annual average basis, or (2) 0.9 Mg/yr (1 tpy) of 
benzene emissions.
    The EPA is proposing an additional action level based on the 
county-level urban versus rural location of area source TEG dehydration 
units. Thus, only those selected area source TEG dehydration units 
located in counties classified as urban (see section III of this 
preamble) and also meeting or exceeding the actual natural gas 
throughput and benzene emission rate action levels will be required to 
install air emission controls on all process vents. Units (1) below 
these cutoffs or (2) located in counties classified as rural would not 
have to be controlled for HAP emissions under the proposed rules.
    The EPA evaluated the use of a risk-distance applicability criteria 
as an alternative to the urban area criteria. The EPA is requesting 
comment, along with supporting documentation, on the use of a risk-
distance applicability criteria for focussing the area source 
provisions of this proposed regulation to only those area source TEG 
dehydration units that meet a risk-distance criteria for applicability.
    TEG dehydration units located at natural gas transmission and 
storage facilities emit similar emissions and have a similar emission 
potential to those located at oil and natural gas production 
facilities. However, insufficient information was available to conduct 
an area source finding analysis for the natural gas transmission and 
storage source category.
    The EPA is currently evaluating whether TEG dehydration units 
located at natural gas transmission and storage area sources result in 
an unacceptable risk and should be listed and regulated as an area 
source. The EPA is soliciting comment, along with supporting 
documentation, in this notice on the emissions, location, and number of 
TEG dehydration units located at natural gas transmission and storage 
area sources. Information supplied to the EPA should either support or 
negate the need for an area source listing.

E. HAP Emission Points

    The EPA specifically requests information on potential HAP 
emissions that may be associated with (1) process vents at amine 
treating units and sulfur plants, (2) transfer and storage of pipeline 
pigging wastes, and (3) combustion sources located at oil and natural 
gas production and natural gas transmission and storage facilities. The 
EPA has not identified sufficient data to adequately address the 
potential of HAP emissions from these emission points in these source 
categories. Thus, the EPA is requesting comment, along with supporting 
documentation, on HAP emissions from these emission points.

F. Storage Vessels at Natural Gas Transmission and Storage Facilities

    The EPA had insufficient information to determine whether 
significant HAP-emitting storage vessels warranting control are located 
at natural gas transmission and storage facilities that are major 
sources of HAP. Therefore, the EPA is soliciting information and 
comment, along with supporting documentation, regarding the storage 
vessels located at these sources.
    Specifically, the EPA is requesting information and comment, along 
with supporting documentation, on whether the storage vessels currently 
being proposed for control under the oil and natural gas production 
NESHAP are similar to those located at natural gas transmission and 
storage facilities.

G. Cost Impact and Production Recovery Credits

    The EPA specifically requests comments on the cost impact and the 
production recovery credits as discussed in section IV of the preamble. 
In addition to its solicitation for comments, the EPA also requests 
documentation to support cost impact or recovery credit comments.

XI. Administrative Requirements

A. Docket

    The docket for these rulemakings is A-94-04. The docket is an 
organized and complete file of all the information considered by the 
EPA in the development of this rulemaking. The principal purposes of 
the docket are (1) to allow interested parties a means to

[[Page 6310]]

identify and locate documents so that they can effectively participate 
in the rulemaking process and (2) to serve as the record in case of 
judicial review (except for interagency review materials) [section 
307(d)(7)(A) of the Act]. This docket contains copies of the regulatory 
text, BID, BID references, and technical memoranda documenting the 
information considered by the EPA in the development of the proposed 
rules. The docket is available for public inspection at the EPA's Air 
and Radiation Docket and Information Center, the location of which is 
given in the ADDRESSES section of this notice.

B. Paperwork Reduction Act

    The information collection requirements in these proposed rules 
have been submitted for approval to the Office of Management and Budget 
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. 
Information Collection Request (ICR) documents have been prepared by 
the EPA (ICR Nos. 1788.01 and 1789.01) and copies may be obtained from 
Sandy Farmer, OPPE Regulatory Information Division; U.S. Environmental 
Protection Agency (2137); 401 M Street, S.W.; Washington, DC 20460 or 
by calling (202) 260-2740.
    Information is required to ensure compliance with the provisions of 
the proposed rules. If the relevant information were collected less 
frequently, the EPA would not be reasonably assured that a source is in 
compliance with the proposed rules. In addition, the EPA's authority to 
take administrative action would be reduced significantly.
    The proposed rules would require that facility owners or operators 
retain records for a period of five years, which exceeds the three year 
retention period contained in the guidelines in 5 CFR 1320.6. The five 
year retention period is consistent with the provisions of the General 
Provisions of 40 CFR Part 63, and with the five year records retention 
requirement in the operating permit program under Title V of the CAA.
    All information submitted to the EPA for which a claim of 
confidentiality is made will be safeguarded according to the EPA 
policies set forth in Title 40, Chapter 1, Part 2, Subpart B, 
Confidentiality of Business Information. See 40 CFR 2; 41 FR 36902, 
September 1, 1976; amended by 43 FR 3999, September 8, 1978; 43 FR 
42251, September 28, 1978; and 44 FR 17674, March 23, 1979. Even where 
the EPA has determined that data received in response to an ICR is 
eligible for confidential treatment under 40 CFR Part 2, Subpart B, the 
EPA may nonetheless disclose the information if it is ``relevant in any 
proceeding'' under the statute [42 U.S.C. 7414(C); 40 CFR 2.301(g)]. 
The information collection complies with the Privacy Act of 1974 and 
Office of Management and Budget (OMB) Circular 108.
    Information to be reported consists of emission data and other 
information that are not of a sensitive nature. No sensitive personal 
or proprietary data are being collected.
    The estimated annual average hour burden for the major source 
provisions of the proposed oil and natural gas production NESHAP is 169 
hours per respondent. The estimated annual average cost of this burden 
is $7,300 for each of the estimated 484 existing and new (projected) 
respondents.
    The estimated annual average hour burden for the area source 
provisions of the proposed oil and natural gas production NESHAP is 56 
hours per respondent. The estimated annual average cost of this burden 
is $2,400 for each of the estimated 572 existing and new (projected) 
respondents.
    The estimated annual average hour burden for the major source 
provisions of the proposed natural gas transmission and storage NESHAP 
is 77 hours per respondent. The estimated annual average cost of this 
burden is $3,300 for each of the estimated 5 existing respondents.
    Reports are required on a semi-annual and annual basis (depending 
upon the reports) and as required, as in the case of startup, shutdown, 
and malfunction plans. 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 the 
EPA's regulations are listed in 40 CFR part 9 and 48 CFR Chapter 15.
    Comments are requested on the EPA'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 ICRs to the 
Director, OPPE Regulatory Information Division; U.S. Environmental 
Protection Agency (2137); 401 M Street, S.W., Washington, DC 20460; and 
to the Office of Information and Regulatory Affairs, Office of 
Management and Budget, 725 17th Street, N.W., Washington, DC 20503, 
marked ``Attention: Desk Officer for EPA.'' Include the ICR number(s) 
in any correspondence. Since OMB is required to make a decision 
concerning the ICR's between 30 and 60 days after February 6, 1998, a 
comment to OMB is best assured of having its full effect if OMB 
receives it by March 9, 1998. The final rules will respond to any OMB 
or public comments on the information collection requirements contained 
in this proposal.

C. Executive Order 12866

    Under Executive Order 12866 [58 FR 5173 (October 4, 1993)], the EPA 
must determine whether the regulatory action is ``significant'' and 
therefore subject to OMB review and the requirements of the Executive 
Order. The criteria set forth in section 1 of the Order for determining 
whether a regulation is a significant rule are as follows: (1) Is 
likely to have an annual effect on the economy of $100 million or more, 
or adversely and materially affect a sector of the economy, 
productivity, competition, jobs, the environment, public health or 
safety, or State, local or tribal governments or communities; (2) is 
likely to create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency; (3) is likely to materially 
alter the budgetary impact of entitlements, grants, user fees or loan 
programs, or the rights and obligations of recipients thereof; or (4) 
is likely to raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    Based on criteria 1, 2, and 3, this action is not a ``significant 
regulatory action'' within the meaning of Executive Order 12866. 
However, the OMB has deemed it significant under criterion 4 and has 
requested review of this proposed rulemaking package. Therefore, the 
EPA submitted this action to OMB for review. Changes made in response 
to OMB suggestions or recommendations are documented in the public 
record.

[[Page 6311]]

D. Regulatory Flexibility

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to conduct a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements, 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 not-for-profit enterprises, and small governmental 
jurisdictions. These proposed rules will not have a significant 
economic impact on a substantial number of small entities. According to 
Wards Business Directory (1993), there are 1,152 firms in the seven 
affected Standard Industrial Classification (SIC) codes and 735 of 
these firms meet the Small Business Administration (SBA) definition of 
a small entity.
    The number of affected small entities for these rules is likely to 
be minimal due to several considerations in these rules that minimize 
the burden on all firms, both small and large. These considerations 
include exempting from control requirements those glycol dehydration 
units located at major or area sources with (1) an actual flowrate of 
natural gas to the glycol dehydration unit less than 85 m\3\/day (3.0 
MMSCF/D), on an annual average basis, or (2) benzene emissions less 
than 0.9 Mg/yr (1 tpy). In addition, emission controls are limited to 
those area source glycol dehydration units located in urban areas.
    In a screening of potential impacts on a sample of small entities, 
the EPA found that there are minimal impacts on these entities. The 
weighted average of control costs as a percent of sales is 0.09 of one 
percent for the small firms in the sample, while a maximum value of 1.1 
percent results for only two of these firms. The analysis also 
indicates that with the regulations, the change in measures of 
profitability are minimal (i.e., 0.11 of one percent change in the 
cost-to-sales ratio for small firms), and there are no indications of 
financial failures or employment losses for both small and large firms. 
The screening analysis for these rules is detailed in the Economic 
Impact Analysis (see Docket No. A-94-04).
    Therefore, I certify that this action will not have a significant 
economic impact on a substantial number of small entities.

E. Unfunded Mandates

    Title II of the Unfunded Mandate 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, the 
EPA generally must prepare a written statement, including a cost-
benefit analysis, for the proposed and final rules with ``Federal 
mandates'' that may result in expenditures to State, local, and tribal 
governments, in the aggregate, or to the private sector, of $100 
million or more in any one year. Before promulgating an EPA rule for 
which a written statement is needed, section 205 of the UMRA generally 
requires the EPA to identify and consider a reasonable number of 
regulatory alternatives and adopt the least costly, most cost-
effective, or least burdensome alternative that achieves the objectives 
of the rule. The provisions of section 205 do not apply when they are 
inconsistent with applicable law. Moreover, section 205 allows the EPA 
to adopt an alternative other than the least costly, most cost-
effective, or least burdensome alternative if the Administrator 
publishes with the final rule an explanation why that alternative was 
not adopted. Before the EPA establishes any regulatory requirements 
that may significantly or uniquely affect small governments, including 
tribal governments, it must have developed under section 203 of the 
UMRA a small government agency plan. The plan must provide for 
notifying potentially affected small governments, enabling officials of 
affected small governments to have meaningful and timely input in the 
development of the EPA regulatory proposals with significant Federal 
intergovernmental mandates, and informing, educating, and advising 
small governments on compliance with the regulatory requirements.
    The EPA has determined that these rules do not contain a Federal 
mandate that may result in expenditures of $100 million or more for 
State, local, and tribal governments, in the aggregate or the private 
sector in any one year. The EPA's total estimated annual net costs of 
the proposed rules is $10 million, including MIRR costs. Thus, today's 
rules are not subject to the requirements of sections 202 and 205 of 
the UMRA.
    The EPA has determined that these rules contain no regulatory 
requirements that might significantly or uniquely affect small 
governments. No small government entities have been identified that 
have involvement with these source categories and, as such, are not 
covered by the regulatory requirements of the proposed regulations.

List of Subjects in 40 CFR Part 63

    Environmental protection, Air pollution control, Air emissions 
control, Associated equipment, Black oil, Condensate, Custody transfer, 
Equipment leaks, Glycol dehydration units, Hazardous air pollutants, 
Hazardous substances, Natural gas, Intergovernmental relations, Natural 
gas processing plants, Natural gas transmission and storage, Oil and 
natural gas production, Pipelines, Organic liquids distribution (non-
gasoline), Reporting and recordkeeping requirements, Storage vessels, 
Tank batteries, Tanks, Triethylene glycol.

    Dated: November 24, 1997.
Carol M. Browner,
Administrator.
    For the reasons set out in the preamble, title 40, chapter I, part 
63 of the Code of Federal Regulations is proposed to be amended as 
follows:

PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 
FOR SOURCE CATEGORIES

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

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

    2. Part 63 is amended by adding subpart HH to read as follows:

Subpart HH--National Emission Standards for Hazardous Air 
Pollutants From Oil and Natural Gas Production Facilities

Sec.
63.760  Applicability and designation of affected source.
63.761  Definitions.
63.762  [Reserved]
63.763  [Reserved]
63.764  General standards.
63.765  Glycol dehydration unit process vent standards.
63.766  Storage vessel standards.
63.767  [Reserved]
63.768  [Reserved]
63.769  Equipment leak standards.
63.770  [Reserved]
63.771  Control requirements.
63.772  Test methods and compliance procedures.
63.773  Inspection and monitoring requirements.
63.774  Recordkeeping requirements.
63.775  Reporting requirements.
63.776  Delegation of authority. [Reserved]
63.777  Alternative means of emission limitation.
63.778  [Reserved]
63.779  [Reserved]
Table 1 to Subpart HH--List of Air Pollutants for Subpart HH
Table 2 to Subpart HH--Applicability of 40 CFR Part 63 General 
Provisions to Subpart HH

[[Page 6312]]

Subpart HH--National Emission Standards for Hazardous Air 
Pollutants From Oil and Natural Gas Production Facilities


Sec. 63.760  Applicability and designation of affected source.

    (a) This subpart applies to the owners or operators of emission 
points, as specified in paragraph (b) of this section, that are located 
at oil and natural gas production facilities that meet the specified 
criteria in paragraphs (a)(1), (a)(2), and (a)(3) of this section.
    (1) Facilities that process, upgrade, or store hydrocarbon liquids 
prior to the point of custody transfer;
    (2) Facilities that process, upgrade, or store natural gas prior to 
the point at which natural gas enters the natural gas transmission and 
storage source category or is delivered to a final end user; and
    (3) Both major and area sources of HAP.
    (b) The affected sources for major sources are listed in paragraph 
(b)(1) of this section and for area sources in paragraph (b)(2) of this 
section.
    (1) For major sources, the affected source shall comprise each 
emission point located at a facility that meets the criteria specified 
in paragraph (a) of this section and listed in paragraphs (b)(1)(i) 
through (b)(1)(iv) of this section.
    (i) Each glycol dehydration unit;
    (ii) Each storage vessel with flash emissions;
    (iii) The group of all ancillary equipment, except compressors; and
    (iv) Compressors intended to operate in volatile organic hazardous 
air pollutant service (as defined in Sec. 63.761).
    (2) For area sources, the affected source includes each triethylene 
glycol dehydration unit located at a facility that meets the criteria 
specified in paragraph (a) of this section.
    (c) [Reserved]
    (d) The owner or operator of a facility that does not contain an 
affected source as specified in paragraph (b) of this section is not 
subject to the requirements of this subpart.
    (e) The owner or operator of a facility that exclusively processes, 
stores, or transfers black oil (as defined in Sec. 63.761) is not 
subject to the requirements of this subpart.
    (f) The owner or operator of an affected source shall achieve 
compliance with the provisions of this subpart by the dates specified 
in paragraphs (f)(1) and (f)(2) of this section.
    (1) The owner or operator of an affected source the construction or 
reconstruction of which commenced before February 6, 1998, shall 
achieve compliance with the provisions of the subpart as expeditiously 
as practical after [the date of publication of the final rule], but no 
later than three years after [the date of publication of the final 
rule] except as provided for in Sec. 63.6(i).
    (2) The owner or operator of an affected source the construction or 
reconstruction of which commences on or after February 6, 1998, shall 
achieve compliance with the provisions of this subpart immediately upon 
startup or [the date of publication of the final rule], whichever date 
is later.
    (g) The following provides owners or operators of an affected 
source with information on overlap of this subpart with other 
regulations for equipment leaks.
    (1) After the compliance dates specified in paragraph (f) of this 
section, ancillary equipment that is subject to this subpart and that 
is also subject to and controlled under the provisions of 40 CFR part 
60, subpart KKK is only required to comply with the requirements of 40 
CFR part 60, subpart KKK.
    (2) After the compliance dates specified in paragraph (f) of this 
section, ancillary equipment that is subject to this subpart and is 
also subject to and controlled under the provisions of 40 CFR part 61, 
subpart V is only required to comply with the requirements of 40 CFR 
part 61, subpart V.
    (3) After the compliance dates specified in paragraph (f) of this 
section, ancillary equipment that is subject to this subpart and is 
also subject to and controlled under the provisions of subpart H of 
this part is only required to comply with the requirements of subpart H 
of this part.
    (h) An owner or operator of an affected source that is a major 
source or located at a major source and is subject to the provisions of 
this subpart is also subject to 40 CFR part 70 permitting requirements. 
Unless otherwise required by the State, the owner or operator of an 
area source subject to the provisions this subpart is not required to 
obtain a permit under part 70 of title 40 of the Code of Federal 
Regulations.


Sec. 63.761  Definitions.

    All terms used in this subpart shall have the meaning given them in 
the Clean Air Act, subpart A of this part (General Provisions), and in 
this section. If the same term is defined in subpart A and in this 
section, it shall have the meaning given in this section for purposes 
of this subpart.
    Alaskan North Slope means the approximately 180,000 square 
kilometer area (69,000 square mile area) extending from the Brooks 
Range to the Arctic Ocean.
    Ancillary equipment means any of the following pieces of equipment: 
pumps, compressors, pressure relief devices, sampling connection 
systems, open-ended valves or lines, valves, flanges and other 
connectors, or product accumulator vessels.
    API gravity means the weight per unit volume of hydrocarbon liquids 
as measured by a system recommended by the American Petroleum Institute 
(API) and is expressed in degrees.
    Associated equipment, as used in this subpart and as referred to in 
section 112(n)(4) of the Act, means equipment associated with an oil or 
natural gas exploration or production well, and includes all equipment 
from the wellbore to the point of custody transfer, except glycol 
dehydration units and storage vessels with the potential for flash 
emissions.
    Average concentration, as used in this subpart, means the annual 
average flow rate, as determined according to the procedures specified 
in Sec. 63.772(b).
    Black oil means hydrocarbon (petroleum) liquid with a gas-to-oil 
ratio (GOR) less than 50 cubic meters (1,750 cubic feet) per barrel and 
an API gravity less than 40 degrees.
    Boiler means any enclosed combustion device that extracts useful 
energy in the form of steam and that is not an incinerator.
    Closed-vent system means a system that is not open to the 
atmosphere and that is composed of piping, ductwork, connections, and, 
if necessary, flow inducing devices that transport gas or vapor from an 
emission point to a control device or back into the process. If gas or 
vapor from regulated equipment is routed to a process (e.g., to a fuel 
gas system), the process shall not be considered a closed vent system 
and is not subject to closed vent system standards.
    Combustion device means an individual unit of equipment such as a 
flare, incinerator, process heater, or boiler used for the combustion 
of volatile organic hazardous air pollutant vapors.
    Compressor means a piece of equipment that increases the pressure 
of a process gas by positive displacement, employing linear movement of 
the drive shaft.
    Condensate means hydrocarbon liquid that condenses because of 
changes in temperature, pressure, or both, and remains liquid at 
standard conditions.
    Continuous recorder means a data recording device that either 
records an instantaneous data value at least once

[[Page 6313]]

every 15 minutes or records 15-minute or more frequent block average 
values.
    Continuous seal means a seal that forms a continuous closure that 
completely covers the space between the wall of the storage vessel and 
the edge of the floating roof. A continuous seal may be a vapor-
mounted, liquid-mounted, or metallic shoe seal.
    Control device means any equipment used for recovering or oxidizing 
hazardous air pollutant (HAP) and volatile organic compound (VOC) 
vapors. Such equipment includes, but is not limited to, absorbers, 
carbon adsorbers, condensers, incinerators, flares, boilers, and 
process heaters. For the purposes of this subpart, if gas or vapor from 
regulated equipment is used, reused, returned back to the process, or 
sold, then the recovery system used, including piping, connections, and 
flow inducing devices, are not considered to be control devices.
    Cover means a device which is placed on top of or over a material 
such that the entire surface area of the material is enclosed and 
sealed, to reduce emissions to the atmosphere. A cover may have 
openings (such as access hatches, sampling ports, and gauge wells) if 
those openings are necessary for operation, inspection, maintenance, or 
repair of the unit on which the cover is installed, provided that each 
opening is closed and sealed when the opening is not in use. In 
addition, a cover may have one or more safety devices. Examples of a 
cover include a fixed-roof installed on a tank, an external floating 
roof installed on a tank, and a lid installed on a drum or other 
container.
    Custody transfer means the transfer of hydrocarbon liquids or 
natural gas, after processing and/or treatment in the producing 
operations, from storage vessels or automatic transfer facilities to 
pipelines or any other forms of transportation. For the purposes of 
this subpart, the EPA considers the point at which natural gas enters a 
natural gas processing plant as a point of custody transfer.
    Equipment leak means emissions of hazardous air pollutants from a 
pump, compressor, pressure relief device, sampling connection system, 
open-ended valve or line, valve, or instrumentation system.
    Facility means any grouping of equipment: where hydrocarbon liquids 
are processed, upgraded, 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 source category. For the 
purpose of a major source determination, means oil and natural gas 
production and processing equipment that is located within the 
boundaries of an individual surface site. 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 unit areas, surface fee 
tracts, or surface lease tracts 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, graded pad sites, and 
natural gas processing plants.
    Field natural gas means natural gas extracted from a production 
well prior to entering the first stage of processing, such as 
dehydration.
    Fill or filling means the introduction of a material into a storage 
vessel.
    Fixed-roof means a cover that is mounted on a waste management unit 
or storage vessel in a stationary manner and that does not move with 
fluctuations in liquid level.
    Flame zone means the portion of the combustion chamber in a boiler 
occupied by the flame envelope.
    Flash tank. See definition for gas-condensate-glycol (GCG) 
separator.
    Flow indicator means a device that indicates whether gas flow is 
present in a line.
    Gas-condensate-glycol (GCG) separator means a two-or three-phase 
separator through which the ``rich'' glycol stream of a glycol 
dehydration unit is passed to remove entrained gas and hydrocarbon 
liquid. The GCG separator is commonly referred to as a flash separator 
or flash tank.
    Gas-to-oil ratio (GOR) means the number of standard cubic meters 
(cubic feet) of gas produced per barrel of crude oil or other 
hydrocarbon liquid.
    Glycol dehydration unit means a device in which a liquid glycol 
absorbent directly contacts a natural gas stream (that is circulated 
counter current to the glycol flow) and absorbs water vapor in a 
contact tower or absorption column (absorber). The glycol contacts and 
absorbs water vapor and other gas stream constituents from the natural 
gas and becomes ``rich'' glycol. This glycol is then regenerated by 
distilling the water and other gas stream constituents in the glycol 
dehydration unit reboiler. The distilled or ``lean'' glycol is then 
recycled back to the absorber.
    Glycol dehydration unit reboiler vent means the vent through which 
exhaust from the reboiler of a glycol dehydration unit passes from the 
reboiler to the atmosphere.
    Glycol dehydration unit process vent means either the glycol 
dehydration unit reboiler vent or the vent from the GCG separator 
(flash tank).
    Hazardous air pollutants or HAP means the chemical compounds listed 
in section 112(b) of the Act. All chemical compounds listed in section 
112(b) of the Act need to be considered when making a major source 
determination. Only the HAP compounds listed in Table 1 of this subpart 
need to be considered when determining applicability and compliance.
    Hydrocarbon liquid means any naturally occurring, unrefined 
petroleum liquid.
    In VOHAP service means that a piece of ancillary equipment either 
contains or contacts a fluid (liquid or gas) which has a total volatile 
organic HAP (VOHAP) concentration equal to or greater than 10 percent 
by weight as determined according to the provisions of 40 CFR 
61.245(d).
    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 or pump station shall not be 
aggregated with emissions from other similar units, to determine 
whether such emission points or stations are major sources, even when 
emission points are in a contiguous area or under common control;
    (2) Emissions from processes, operations, or equipment that are not 
part of the same facility, as defined in this section, shall not be 
aggregated; and
    (3) For facilities that are production field facilities, only HAP 
emissions from glycol dehydration units and storage tanks with flash 
emission potential shall be counted in a major source determination.
    Natural gas means the gaseous mixture of hydrocarbon gases and 
vapors, primarily consisting of methane, ethane, propane, butane, 
pentane, and hexane, along with water vapor and other constituents.
    Natural gas liquids (NGLs) means the hydrocarbons, such as ethane, 
propane, butane, pentane, natural gasoline, and condensate that are 
extracted from field gas.
    Natural gas processing plant (gas plant) means any processing site 
engaged in:
    (1) The extraction of natural gas liquids from field gas; or
    (2) The fractionation of mixed NGLs to natural gas products.

[[Page 6314]]

    No detectable emissions means no escape of HAP from a device or 
system to the atmosphere as determined by:
    (1) Testing the device or system in accordance with the 
requirements of Sec. 63.772(c); and
    (2) No visible openings or defects in the device or system such as 
rips, tears, or gaps.
    Operating parameter value means a minimum or maximum value 
established for a control device or process parameter which, if 
achieved by itself or in combination with one or more other operating 
parameter values, determines that an owner or operator has complied 
with an applicable emission limitation or standard.
    Operating permit means a permit required by 40 CFR part 70 or part 
71.
    Organic monitoring device means a unit of equipment used to 
indicate the concentration level of organic compounds exiting a 
recovery device based on a detection principle such as infra-red, 
photoionization, or thermal conductivity.
    Point of material entry means at the point where a material first 
enters a source subject to this subpart.
    Primary fuel means the fuel that provides the principal heat input 
(i.e., more than 50-percent) to the device. To be considered primary, 
the fuel must be able to sustain operation without the addition of 
other fuels.
    Process heater means a device that transfers heat liberated by 
burning fuel directly to process streams or to heat transfer liquids 
other than water.
    Produced water means water:
    (1) That is extracted from the earth from an oil or natural gas 
production well; or
    (2) That is separated from crude oil, condensate, or natural gas 
after extraction.
    Production field facilities means those facilities located prior to 
the point of custody transfer.
    Production well means any hole drilled in the earth from which 
crude oil, condensate, or field natural gas is extracted.
    Relief device means a device used only to release an unplanned, 
non-routine discharge. A relief device discharge can result from an 
operator error, a malfunction such as a power failure or equipment 
failure, or other unexpected cause that requires immediate venting of 
gas from process equipment in order to avoid safety hazards or 
equipment damage.
    Safety device means a device that is not used for planned or 
routine venting of liquids, gases, or fumes from the unit or equipment 
on which the device is installed; and the device remains in a closed, 
sealed position at all times except when an unplanned event requires 
that the device open for the purpose of preventing physical damage or 
permanent deformation of the unit or equipment on which the device is 
installed in accordance with good engineering and safety practices for 
handling flammable, combustible, explosive, or other hazardous 
materials. Examples of unplanned events which may require a safety 
device to open include failure of an essential equipment component or a 
sudden power outage.
    Storage vessel means a tank or other vessel that is designed to 
contain an accumulation of crude oil, condensate, intermediate 
hydrocarbon liquids, or produced water and that is constructed 
primarily of non-earthen materials (e.g., wood, concrete, steel, 
plastic) that provide structural support.
    Storage vessel with the potential for flash emissions means any 
storage vessel that contains a hydrocarbon with a GOR equal to or 
greater than 50 cubic meters (1,750 cubic feet) per barrel or an API 
gravity equal to or greater than 40 degrees.
    Surface site means the graded pad, gravel pad, foundation, 
platform, or immediate physical location upon which equipment is 
physically affixed.
    Tank battery means a collection of equipment used to separate, 
treat, store, and transfer crude oil, condensate, natural gas, and 
produced water. A tank battery typically receives crude oil, 
condensate, natural gas, or some combination of these extracted 
products from several production wells for accumulation and separation 
prior to transmission to a natural gas plant or petroleum refinery. A 
tank battery may or may not include a glycol dehydration unit.
    Temperature monitoring device means a unit of equipment used to 
monitor temperature and having an accuracy of 1 percent of 
the temperature being monitored expressed in  deg.C, or 
0.5 deg.C, whichever is greater.
    Total organic compounds or TOC, as used in this subpart, means 
those compounds measured according to the procedures of Method 18, 40 
CFR part 60, appendix A.
    Urban area is defined by use of the U.S. Department of Commerce's 
Bureau of the Census statistical data to classify every county in the 
U.S. into one of the three classifications:
    (1) Urban-1 areas which consist of metropolitan statistical areas 
(MSA) with a population greater than 250,000;
    (2) Urban-2 areas which are defined as all other areas designated 
urban by the Bureau of Census (areas which comprise one or more central 
places and the adjacent densely settled surrounding fringe that 
together have a minimum of 50,000 persons). The urban fringe consists 
of contiguous territory having a density of at least 1,000 persons per 
square mile; or
    (3) Rural areas which are those counties not designated as urban by 
the Bureau of the Census.
    Volatile organic hazardous air pollutant concentration or VOHAP 
concentration means the fraction by weight of all HAP contained in a 
material as determined in accordance with procedures specified in 
Sec. 63.772(a).


Sec. 63.762  [Reserved]


Sec. 63.763  [Reserved]


Sec. 63.764  General standards.

    (a) Table 2 of this subpart specifies the provisions of subpart A 
(General Provisions) that apply and those that do not apply to owners 
and operators of affected sources subject to this subpart.
    (b) All reports required under this subpart shall be sent to the 
Administrator at the appropriate address listed in Sec. 63.13. If 
acceptable to both the Administrator and the owner or operator of a 
source, reports may be submitted on electronic media.
    (c) Except as specified in paragraph (e) of this section, the owner 
or operator of an affected source located at an existing or new major 
source shall comply with the standards in this subpart as specified in 
paragraphs (c)(1) through (c)(3) of this section.
    (1) For each glycol dehydration unit process vent subject to this 
subpart, the owner or operator shall comply with the requirements 
specified in paragraphs (c)(1)(i) through (c)(1)(iii) of this section.
    (i) The owner or operator shall comply with the control 
requirements for glycol dehydration unit process vents specified in 
Sec. 63.765;
    (ii) The owner or operator shall comply with the monitoring 
requirements of Sec. 63.773; and
    (iii) The owner or operator shall comply with the recordkeeping and 
reporting requirements of Secs. 63.774 and 63.775.
    (2) For each storage vessel with the potential for flash emissions 
and an actual throughput of hydrocarbon liquids equal to or greater 
than 500 barrels per day (BPD), the owner or operator shall comply with 
the requirements specified in paragraphs (c)(2)(i) through (c)(2)(iii) 
of this section.
    (i) The control requirements for storage vessels specified in 
Sec. 63.766;
    (ii) The monitoring requirements of Sec. 63.773; and

[[Page 6315]]

    (iii) The recordkeeping and reporting requirements of Secs. 63.774 
and 63.775.
    (3) For ancillary equipment (as defined in Sec. 63.761) at a 
natural gas processing plant subject to this subpart, the owner or 
operator shall comply with the requirements for equipment leaks 
specified in Sec. 63.769.
    (d) The owner or operator of an affected source located at an area 
source of HAP emissions shall comply with the standards in this subpart 
as specified in paragraphs (d)(1) through (d)(3) of this section.
    (1) The control requirements for glycol dehydration unit process 
vents specified in Sec. 63.765;
    (2) The monitoring requirements of Sec. 63.773; and
    (3) The recordkeeping and reporting requirements of Secs. 63.774 
and 63.775.
    (e) The owner or operator is exempt from the requirements of 
paragraphs (c)(1) and (d) of this section if the actual annual average 
flow of gas to the glycol dehydration unit is less than 85 thousand 
cubic meters per day (3.0 million standard cubic feet per day) or 
emissions of benzene from the unit to the atmosphere are less than 0.9 
megagram per year (1 ton per year). The flow of natural gas to the unit 
and the emissions of benzene from the unit shall be determined by the 
procedures specified in Sec. 63.772(b). This determination must be made 
available to the Administrator upon request. In addition, the owner or 
operator is exempt from the requirements of paragraph (d) of this 
section if the glycol dehydration unit is not located in a county 
classified as an Urban area as defined in Sec. 63.761.
    (f) Each owner or operator of a major HAP source subject to this 
subpart is required to apply for a 40 CFR part 70 or part 71 operating 
permit from the appropriate permitting authority. If the Administrator 
has approved a State operating permit program under 40 CFR part 70, the 
permit shall be obtained from the State authority. If the State 
operating permit program has not been approved, the owner or operator 
of a source shall apply to the EPA Regional Office pursuant to 40 CFR 
part 71.
    (g) Unless otherwise required by the State, the owner or operator 
of an area source subject to the provisions of this subpart is not 
required to obtain a permit under part 70 of title 40 of the Code of 
Federal Regulations.
    (h) An owner or operator of an affected source that is:
    (1) A major source or located at a major source; or
    (2) An area source subject to the provisions of this subpart that 
is in violation of an operating parameter value is in violation of the 
applicable emission limitation or standard.


Sec. 63.765  Glycol dehydration unit process vents standards.

    (a) This section applies to each glycol dehydration unit process 
vent that must be controlled for HAP emissions as specified in 
Sec. 63.764(c)(1)(i) and (d)(1).
    (b) Except as provided in paragraph (c) of this section, an owner 
or operator of a glycol dehydration unit process vent shall comply with 
the requirements specified in paragraphs (b)(1) and (b)(2) of this 
section.
    (1) For each glycol dehydration unit process vent, the owner or 
operator shall control air emissions by connecting the process vent to 
a control device through a closed-vent system designed and operated in 
accordance with the requirements of Sec. 63.771(c) and (d).
    (2) One or more safety devices that vent directly to the atmosphere 
may be used on the air emission control equipment complying with 
paragraph (b)(1) of this section.
    (c) As an alternative to the requirements of paragraph (b) of this 
section, the owner or operator may comply with one of the requirements 
specified in paragraphs (c)(1) through (c)(3) of this section.
    (1) The owner or operator shall control air emissions by connecting 
the process vent to a process natural gas line through a closed-vent 
system designed and operated in accordance with the requirements of 
Sec. 63.771(c).
    (2) The owner or operator shall demonstrate, to the Administrator's 
satisfaction, that the total HAP emissions to the atmosphere from the 
glycol dehydration unit reboiler vent and GCG separator (flash tank) 
vent (if present) are reduced by 95 percent through process 
modifications.
    (3) Control of HAP emissions from a GCG separator (flash tank) vent 
is not required if the owner or operator demonstrates, to the 
Administrator's satisfaction, that total HAP emissions to the 
atmosphere from the glycol dehydration unit reboiler vent and GCG 
separator (flash tank) vent are reduced by 95 percent.


Sec. 63.766  Storage vessel standards.

    (a) This section applies to each storage vessel that must be 
controlled for HAP emissions as specified in Sec. 63.764(c)(2).
    (b) The owner or operator of a storage vessel shall comply with one 
of the control requirements specified in paragraphs (b)(1) through 
(b)(3) of this section.
    (1) The owner or operator of a storage vessel using a cover that is 
connected through a closed-vent system to a control device shall use a 
cover that is designed and operated in accordance with the requirements 
of Sec. 63.771(b). The closed-vent system and control device shall be 
designed and operated in accordance with the requirements of 
Sec. 63.771(c) and (d).
    (2) The owner or operator of a pressure storage vessel that is 
designed to operate as a closed system shall operate the storage vessel 
with no detectable emissions at all times that material is in the 
storage vessel, except as provided for in paragraph (c) of this 
section.
    (3) The owner or operator of a storage vessel using a fixed-roof 
cover with an internal floating roof shall use a fixed-roof cover with 
an internal floating roof designed and operated in accordance with the 
requirements of 40 CFR 60.112b(a)(1).
    (c) One or more safety devices that vent directly to the atmosphere 
may be used on the storage vessel and air emission control equipment 
complying with paragraphs (b)(1) through (b)(3) of this section.


Sec. 63.767  [Reserved]


Sec. 63.768  [Reserved]


Sec. 63.769  Equipment leak standards.

    (a) This section applies to ancillary equipment and compressors (as 
defined in Sec. 63.761) at natural gas processing plants that contain 
or contact a fluid (liquid or gas) that has a total VOHAP concentration 
equal to or greater than 10 percent by weight (determined according to 
the provisions of 40 CFR 61.245(d)) and that operates equal to or 
greater than 300 hours per calendar year.
    (b) This section does not apply to ancillary equipment and 
compressors for which the owner or operator is meeting the requirements 
specified in subpart H of this part; or is meeting the requirements 
specified in 40 CFR part 60, subpart KKK.
    (c) For each piece of ancillary equipment and compressors subject 
to this section located at an existing or new source, the owner or 
operator shall meet the requirements specified in 40 CFR 61.241 through 
61.247, except as specified in paragraphs (c)(1) through (c)(8) of this 
section.
    (1) Each pressure relief device in gas/vapor service shall be 
monitored quarterly and within 5 days after each pressure release to 
detect leaks, except under the following conditions.
    (i) If an owner or operator has obtained permission from the 
Administrator to use an alternative means of emission limitation that

[[Page 6316]]

achieves a reduction in emissions of VOHAP at least equivalent to that 
achieved by the control required in this subpart.
    (ii) If the pressure relief device is located in a nonfractionating 
facility that is monitored only by non-facility personnel, it may be 
monitored after a pressure release the next time the monitoring 
personnel are on site, instead of within 5 days. Such a pressure relief 
device shall not be allowed to operate for more than 30 days after a 
pressure release without monitoring.
    (2) For pressure relief devices, if an instrument reading of 10,000 
parts per million or greater is measured, a leak is detected.
    (3) For pressure relief devices, when a leak is detected, it shall 
be repaired as soon as practicable, but no later than 15 calendar days 
after it is detected, except if a delay in repair of equipment is 
granted under 40 CFR 61.242-10.
    (4) Sampling connection systems are exempt from the requirements of 
40 CFR 61.242-5.
    (5) Pumps in VOHAP service, valves in gas/vapor and light liquid 
service, and pressure relief devices in gas/vapor service that are 
located at a nonfractionating plant that does not have the design 
capacity to process 283 standard cubic meters per day (10 million 
standard cubic feet per day) or more of field gas are exempt from the 
routine monitoring requirements of 40 CFR 61.242-2(a)(1) and paragraphs 
61.242-7(a), and paragraphs (c)(1) through (c)(3) of this section.
    (6) Pumps in VOHAP service, valves in gas/vapor and light liquid 
service, and pressure relief devices in gas/vapor service within a 
natural gas processing plant that is located on the Alaskan North Slope 
are exempt from the routine monitoring requirements of 40 CFR 61.242-
2(a)(1) and 61.242-7(a), and paragraphs (c)(1) through (c)(3) of this 
section.
    (7) Reciprocating compressors in wet gas service are exempt from 
the compressor control requirements of 40 CFR 61.242-3.
    (8) Flares used to comply with this subpart shall comply with the 
requirements of Sec. 63.11(b).


Sec. 63.770  [Reserved]


Sec. 63.771  Control requirements.

    (a) This section applies to each cover, closed-vent system, and 
control device installed and operated by the owner or operator to 
control air emissions.
    (b) Cover requirements. (1) The cover and all openings on the cover 
(e.g., access hatches, sampling ports, and gauge wells) shall be 
designed to operate with no detectable emissions when all cover 
openings are secured in a closed, sealed position.
    (2) The owner or operator shall determine that the cover operates 
with no detectable emissions by testing each opening on the cover in 
accordance with the procedures specified in Sec. 63.772(c) the first 
time material is placed into the unit on which the cover is installed. 
If a leak is detected and cannot be repaired at the time that the leak 
is detected, the material shall be removed from the unit and the unit 
shall not be used until the leak is repaired.
    (3) Each cover opening shall be secured in a closed, sealed 
position (e.g., covered by a gasketed lid or cap) whenever material is 
in the unit on which the cover is installed except during those times 
when it is necessary to use an opening as follows:
    (i) To add material to, or remove material from the unit (this 
includes openings necessary to equalize or balance the internal 
pressure of the unit following changes in the level of the material in 
the unit);
    (ii) To inspect or sample the material in the unit;
    (iii) To inspect, maintain, repair, or replace equipment located 
inside the unit; or
    (iv) To vent liquids, gases, or fumes from the unit through a 
closed-vent system to a control device designed and operated in 
accordance with the requirements of paragraphs (c) and (d) of this 
section.
    (c) Closed-vent system requirements. (1) The closed-vent system 
shall route all gases, vapors, and fumes emitted from the material in 
the unit to a control device that meets the requirements specified in 
paragraph (d) of this section.
    (2) The closed-vent system shall be designed and operated with no 
detectable emissions.
    (3) If the closed-vent system contains one or more bypass devices 
that could be used to divert all or a portion of the gases, vapors, or 
fumes from entering the control device, the owner or operator shall 
meet the requirements specified in paragraphs (c)(3)(i) and (c)(3)(ii) 
of this section.
    (i) For each bypass device, except as provided for in paragraph 
(c)(3)(ii) of this section, the owner or operator shall either:
    (A) Install, calibrate, maintain, and operate a flow indicator at 
the inlet to the bypass device that indicates at least once every 15 
minutes whether gas, vapor, or fume flow is present in the bypass 
device; or
    (B) Secure the valve installed at the inlet to the bypass device in 
the closed position using a car-seal or a lock-and-key type 
configuration. The owner or operator shall visually inspect the seal or 
closure mechanism at least once every month to verify that the valve is 
maintained in the closed position.
    (ii) Low leg drains, high point bleeds, analyzer vents, open-ended 
valves or lines, and safety devices are not subject to the requirements 
of paragraph (c)(3)(i) of this section.
    (d) Control device requirements. (1) The control device used to 
reduce HAP emissions in accordance with the standards of this subpart 
shall be one of the control devices specified in paragraphs (d)(1)(i) 
through (d)(1)(iii) of this section.
    (i) An enclosed combustion device (e.g., thermal vapor incinerator, 
catalytic vapor incinerator, boiler, or process heater) that is 
designed and operated in accordance with one of the following 
performance requirements:
    (A) Reduces the mass content of either TOC or total HAP in the 
gases vented to the device by 95 percent by weight or greater as 
determined in accordance with the requirements of Sec. 63.772(e);
    (B) Reduces the concentration of either TOC or total HAP in the 
exhaust gases at the outlet to the device to a level equal to or less 
than 20 parts per million by volume on a dry basis corrected to 3 
percent oxygen as determined in accordance with the requirements of 
Sec. 63.772(e); or
    (C) Operates at a minimum residence time of 0.5 second at a minimum 
temperature of 760 deg.C. If a boiler or process heater is used as the 
control device, then the vent stream shall be introduced into the flame 
zone of the boiler or process heater.
    (ii) A vapor recovery device (e.g. carbon adsorption system or 
condenser) or other control device that is designed and operated to 
reduce the mass content of either TOC or total HAP in the gases vented 
to the device by 95 percent by weight or greater as determined in 
accordance with the requirements of Sec. 63.772(e).
    (iii) A flare that is designed and operated in accordance with the 
requirements of Sec. 63.11(b).
    (2) Each control device used to comply with this subpart shall be 
operated at all times when material is placed in a unit vented to the 
control device, except when maintenance or repair of a unit cannot be 
completed without a shutdown of the control device. An owner or 
operator may vent more than one unit to a control device used to comply 
with this subpart.

[[Page 6317]]

    (3) The owner or operator shall demonstrate that a control device 
achieves the performance requirements of paragraph (d)(1) of this 
section as specified in paragraphs (d)(3)(i) through (d)(3)(iv) of this 
section.
    (i) An owner or operator shall demonstrate using either a 
performance test as specified in paragraph (d)(3)(iii) of this section 
or a design analysis as specified in paragraph (d)(3)(iv) of this 
section the performance of each control device except for the 
following:
    (A) A flare;
    (B) A boiler or process heater with a design heat input capacity of 
44 megawatts or greater;
    (C) A boiler or process heater into which the vent stream is 
introduced with the primary fuel; or
    (D) A boiler or process heater burning hazardous waste for which 
the owner or operator has either been issued a final permit under 40 
CFR part 270 and complies with the requirements of 40 CFR part 266, 
subpart H; or has certified compliance with the interim status 
requirements of 40 CFR part 266, subpart H.
    (ii) An owner or operator shall demonstrate the performance of each 
flare in accordance with the requirements specified in Sec. 63.11(b).
    (iii) For a performance test conducted to meet the requirements of 
paragraph (d)(3)(i) of this section, the owner or operator shall use 
the test methods and procedures specified in Sec. 63.772(e).
    (iv) For a design analysis conducted to meet the requirements of 
paragraph (d)(3)(i) of this section, the design analysis shall meet the 
requirements specified in paragraphs (d)(3)(iv)(A) and (d)(3)(iv)(B) of 
this section.
    (A) The design analysis shall include analysis of the vent stream 
characteristics and control device operating parameters for the 
applicable control device as specified in paragraphs (d)(3)(iv)(A)(1) 
through (d)(3)(iv)(A)(6) of this section.
    (1) For a thermal vapor incinerator, the design analysis shall 
include the vent stream composition, constituent concentrations, and 
flow rate and shall establish the design minimum and average 
temperatures in the combustion zone and the combustion zone residence 
time.
    (2) For a catalytic vapor incinerator, the design analysis shall 
include the vent stream composition, constituent concentrations, and 
flow rate and shall establish the design minimum and average 
temperatures across the catalyst bed inlet and outlet, and the design 
service life of the catalyst.
    (3) For a boiler or process heater, the design analysis shall 
include the vent stream composition, constituent concentrations, and 
flow rate; shall establish the design minimum and average flame zone 
temperatures and combustion zone residence time; and shall describe the 
method and location where the vent stream is introduced into the flame 
zone.
    (4) For a condenser, the design analysis shall include the vent 
stream composition, constituent concentrations, flow rate, relative 
humidity, and temperature, and shall establish the design outlet 
organic compound concentration level, design average temperature of the 
condenser exhaust vent stream, and the design average temperatures of 
the coolant fluid at the condenser inlet and outlet.
    (5) For a carbon adsorption system that regenerates the carbon bed 
directly on-site in a control device such as a fixed-bed adsorber, the 
design analysis shall include the vent stream composition, constituent 
concentrations, flow rate, relative humidity, and temperature, and 
shall establish the design exhaust vent stream organic compound 
concentration level, adsorption cycle time, number and capacity of 
carbon beds, type and working capacity of activated carbon used for 
carbon beds, design total regeneration stream flow over the period of 
each complete carbon bed regeneration cycle, design carbon bed 
temperature after regeneration, design carbon bed regeneration time, 
and design service life of the carbon.
    (6) For a carbon adsorption system that does not regenerate the 
carbon bed directly on-site in the control device, such as a carbon 
canister, the design analysis shall include the vent stream 
composition, constituent concentrations, flow rate, relative humidity, 
and temperature, and shall establish the design exhaust vent stream 
organic compound concentration level, capacity of carbon bed, type and 
working capacity of activated carbon used for carbon bed, and design 
carbon replacement interval based on the total carbon working capacity 
of the control device and source operating schedule. In addition, these 
systems will incorporate dual carbon canisters in case of emission 
breakthrough occurring in one canister.
    (B) If the owner or operator and the Administrator do not agree on 
a demonstration of control device performance using a design analysis 
then the disagreement shall be resolved using the results of a 
performance test performed by the owner or operator in accordance with 
the requirements of paragraph (d)(3)(iii) of this section. The 
Administrator may choose to have an authorized representative observe 
the performance test.
    (4) The owner or operator shall operate each control device in 
accordance with the requirements specified in paragraphs (d)(4)(i) 
through (d)(4)(iii) of this section.
    (i) The control device shall be operating at all times when gases, 
vapors, and fumes are vented from the unit or units through the closed-
vent system to the control device.
    (ii) For each control device monitored in accordance with the 
requirements of Sec. 63.773(d), the owner or operator shall operate the 
control device such that the actual value of each operating parameter 
required to be monitored in accordance with the requirements of 
Sec. 63.773(d)(3) is greater than the minimum operating parameter value 
or less than the maximum operating parameter value, as appropriate, 
established for the control device in accordance with the requirements 
of Sec. 63.773(d)(4).
    (iii) Failure by the owner or operator to operate the control 
device in accordance with the requirements of paragraph (d)(4)(ii) of 
this section shall constitute a violation of the applicable emission 
standard of this subpart.
    (5) For each carbon adsorption system used as a control device to 
meet the requirements of paragraph (d)(1) of this section, the owner or 
operator shall manage the carbon as specified in paragraphs (c)(5)(i) 
and (c)(5)(ii) of this section.
    (i) Following the initial startup of the control device, all carbon 
in the control device shall be replaced with fresh carbon on a regular, 
predetermined time interval that is no longer than the carbon service 
life established for the carbon adsorption system.
    (ii) All carbon removed from the control device shall be managed in 
one of the following manners:
    (A) Regenerated or reactivated in a thermal treatment unit for 
which the owner or operator has either been issued a final permit under 
40 CFR part 270, and designed and operated the unit in accordance with 
the requirements of 40 CFR part 264, subpart X; or certified compliance 
with the interim status requirements of 40 CFR part 265, subpart P.
    (B) Burned in a hazardous waste incinerator for which the owner or 
operator has been issued a final permit under 40 CFR part 270, and 
designed and operated the unit in accordance with the requirements of 
40 CFR part 264, subpart O.
    (C) Burned in a boiler or industrial furnace for which the owner or 
operator has either been issued a final permit under 40 CFR part 270, 
and designed

[[Page 6318]]

and operated the unit in accordance with the requirements of 40 CFR 
part 266, subpart H, or certified compliance with the interim status 
requirements of 40 CFR part 266, subpart H.


Sec. 63.772  Test methods and compliance procedures.

    (a) Determination of material VOHAP or HAP concentration for 
applicability to the equipment leak standards under this subpart 
(Sec. 63.769).
    (1) An owner or operator is not required to determine the VOHAP or 
HAP concentration for materials placed in units subject to this subpart 
using air emission controls in accordance with the requirements of 
Sec. 63.766.
    (2) An owner or operator shall perform a VOHAP or HAP concentration 
determination at the following times:
    (i) When the material enters the facility in a storage vessel, the 
owner or operator shall perform a VOHAP or HAP concentration 
determination for each storage vessel.
    (ii) When the material enters the facility as a continuous, 
uninterrupted flow of material through a pipeline or other means, the 
owner or operator shall:
    (A) Perform an initial VOHAP or HAP concentration determination 
before the first time any portion of the material is placed in a unit 
subject to this subpart; and
    (B) Perform a new VOHAP or HAP concentration determination whenever 
changes to the material could potentially cause the VOHAP or HAP 
concentration of the material to increase to a level that is equal to 
or greater than the applicable VOHAP or HAP concentration limits 
specified in Sec. 63.769.
    (3) An owner or operator shall determine the VOHAP or HAP 
concentration of a material using either direct measurement as 
specified in paragraph (a)(4) of this section or knowledge of the 
material as specified in paragraph (a)(5) of this section.
    (4) Direct measurement to determine VOHAP or HAP concentration.
    (i) For the purpose of determining the VOHAP or HAP concentration 
at the point of entry, samples of the material shall be collected from 
the storage vessel, pipeline, or other device used to deliver the 
material to the facility before the material is either:
    (A) Combined with other material; or
    (B) Conveyed, handled, or otherwise managed in such a manner that 
the surface of the material is open to the atmosphere.
    (ii) For the purpose of determining the VOHAP or HAP concentration 
at the point of treatment, samples shall be collected at or after the 
point of treatment but before the point where this material is either:
    (A) Combined with other materials;
    (B) Conveyed, handled, or otherwise managed in such a manner that 
the surface of the material is open to the atmosphere; or
    (C) Placed in a unit subject to this subpart.
    (iii) The VOHAP or HAP concentration on a mass-weighted average 
basis shall be determined using the procedure specified in paragraphs 
(a)(4)(iii)(A) through (a)(4)(iii)(D) of this section when the material 
flows as a continuous stream for periods less than or equal to 1 hour.
    (A) A sufficient number of samples, but no less than four samples, 
shall be collected to represent the VOHAP or HAP composition for the 
entire quantity of material. All of the samples shall be collected 
within a 1-hour period.
    (B) Each sample shall be collected in accordance with the 
requirements specified in ``Test Methods for Evaluating Solid Waste, 
Physical/Chemical Methods,'' EPA Publication No. SW-846.
    (C) Each collected sample shall be prepared and analyzed in 
accordance with the requirements of Method 305, 40 CFR part 63, 
appendix A or Method 25D, 40 CFR part 60, appendix A.
    (D) The VOHAP or HAP concentration shall be calculated by using the 
results for all samples analyzed in accordance with paragraph 
(a)(4)(iii)(C) of this section and the following equation:
[GRAPHIC] [TIFF OMITTED] TP06FE98.006

where:

C=VOHAP or HAP concentration of the material on a mass-weighted basis, 
parts per million by weight.
I=Individual sample ``I'' of the material. n=Total number of samples of 
material collected (at least 4) within a 1-hour period.
Ci=Measured VOHAP or HAP concentration of sample ``I'' as 
determined in accordance with the requirements of 
Sec. 63.772(a)(4)(iii)(C), parts per million by weight.

    (iv) The VOHAP or HAP concentration on a mass-weighted average 
basis shall be determined using the procedures specified in paragraphs 
(a)(4)(iv)(A) through (a)(4)(iv)(E) of this section when the material 
flows as a continuous stream of material for periods greater than 1-
hour.
    (A) The averaging period to be used for determining the VOHAP 
concentration on a mass-weighted average basis shall be designated and 
recorded. The averaging period shall represent any time interval that 
the material flows until the time that a new VOHAP or HAP concentration 
determination must be performed pursuant to the requirements of 
paragraph (b) of this section. The averaging period shall not exceed 1 
year.
    (B) A sufficient number of samples, but no less than four samples, 
shall be collected to represent the complete range of VOHAP or HAP 
compositions and VOHAP or HAP quantities that occur in the material 
stream during the entire averaging period due to normal variations in 
the operating conditions for the source, process, or unit generating 
the material. Examples of such normal variations are seasonal 
variations in material quantity, cyclic process operations, or 
fluctuations in ambient temperature.
    (C) Each sample shall be collected in accordance with the 
requirements specified in ``Test Methods for Evaluating Solid Waste, 
Physical/Chemical Methods,'' EPA Publication No. SW-846. Sufficient 
information shall be recorded to document the material quantity and the 
operating conditions for the source, process, or unit generating the 
material represented by each sample collected.
    (D) Each collected sample shall be prepared and analyzed in 
accordance with the requirements of Method 305, 40 CFR part 63, 
appendix A or Method 25D, 40 CFR part 60, appendix A.
    (E) The VOHAP or HAP concentration on a mass-weighted average basis 
shall be calculated by using the results for all samples analyzed in 
accordance with paragraph (a)(4)(vi)(D) of this section and the 
following equation:
[GRAPHIC] [TIFF OMITTED] TP06FE98.007

where:

C=VOHAP or HAP concentration of the material on a mass weighted basis, 
parts per million by weight.
I=Individual sample ``I'' of the material. n=Total number of samples of 
the material collected (at least 4) for the averaging period (not to 
exceed 1 year).
Qi=Mass quantity of stream represented by Ci, kg/
hr.
QT=Total mass quantity of material during the averaging 
period, kilograms per hour.
Ci=Measured VOHAP or HAP concentration of sample ``I'' as 
determined in accordance with the requirements of

[[Page 6319]]

Sec. 63.772(a)(4)(iv)(D), parts per million by weight.

    (5) Knowledge of the material to determine VOHAP or HAP 
concentration.
    (i) Sufficient information shall be prepared and recorded that 
documents the basis for the owner or operator's knowledge of the 
material's VOHAP or HAP concentration. Examples of information that may 
be used as the basis for knowledge of the material include: VOHAP or 
HAP material balances for the source, process, or unit generating the 
material; species-specific VOHAP or HAP chemical test data for the 
material from previous testing still applicable to the current 
operations; documentation that material is generated by a process for 
which no materials containing VOHAP or HAP are used; or previous test 
data for other locations managing the same type of material.
    (ii) If test data are used as the basis for knowledge of the 
material, then the owner or operator shall document the test method, 
sampling protocol, and the means by which sampling variability and 
analytical variability are accounted for in the determination of the 
VOHAP or HAP concentration. For example, an owner or operator may use 
HAP concentration test data that are validated in accordance with 
Method 301, 40 CFR part 63, appendix A as the basis for knowledge of 
the material.
    (iii) An owner or operator using species-specific VOHAP or HAP 
chemical concentration test data as the basis for knowledge of the 
material that is a produced water stream may adjust the test data 
results to the corresponding total VOHAP or HAP concentration value 
that would be reported had the samples been analyzed using Method 305, 
40 CFR part 63, appendix A. To adjust these data, the measured 
concentration for each individual VOHAP or HAP chemical species 
contained in the material is multiplied by the appropriate species-
specific adjustment factor listed in table 34 in the appendix to 40 CFR 
part 63, subpart G.
    (b) Determination of glycol dehydration unit flow rate or benzene 
emissions. The procedures of this paragraph shall be used by an owner 
or operator to determine flow rate or benzene emissions to meet the 
criteria for an exemption from control requirements under 
Sec. 63.764(e).
    (1) The determination of actual flow rate of natural gas to a 
glycol dehydration unit shall be made using the procedures of either 
paragraph (b)(1)(i) or (b)(1)(ii) of this section.
    (i) The owner or operator shall install and operate a monitoring 
instrument that directly measures flow to the glycol dehydration unit 
with an accuracy of plus or minus 2 percent; or
    (ii) The owner or operator shall document that the actual annual 
average flow rate of the dehydration unit is less than 85 thousand 
cubic meters per day (3.0 million standard cubic feet per day).
    (2) The determination of benzene emissions from a glycol 
dehydration unit shall be made using the procedures of either paragraph 
(b)(2)(i) or (b)(2)(ii) of this section.
    (i) The owner or operator shall determine annual benzene emissions 
using the model GRI-GLYCalcTM, Version 3.0 or higher. Inputs 
to the model shall be representative of actual operating conditions of 
the glycol dehydration unit; or
    (ii) The owner or operator shall determine an average mass rate of 
benzene emissions in kilograms per hour through direct measurement by 
performing three runs of Method 18, 40 CFR Part 60, appendix A (or an 
equivalent method), and averaging the results of the three runs. Annual 
emissions in kilograms per year shall be determined by multiplying the 
mass rate by the number of hours the unit is operated per year. This 
result shall be multiplied by 1.1023 E-03 to convert to tons 
per year.
    (c) No detectable emissions test procedure.
    (1) The no detectable emissions test procedure shall be conducted 
in accordance with Method 21, 40 CFR part 60, appendix A.
    (2) The detection instrument shall meet the performance criteria of 
Method 21, 40 CFR part 60, appendix A, except that the instrument 
response factor criteria in section 3.1.2(a) of Method 21 shall be for 
the average composition of the fluid and not for each individual 
organic compound in the stream.
    (3) The detection instrument shall be calibrated before use on each 
day of its use by the procedures specified in Method 21, 40 CFR part 
60, appendix A.
    (4) Calibration gases shall be as follows:
    (i) Zero air (less than 10 parts per million by volume hydrocarbon 
in air); and
    (ii) A mixture of methane in air at a concentration less than 
10,000 parts per million by volume.
    (5) The background level shall be determined according to the 
procedures in Method 21, 40 CFR part 60, appendix A.
    (6) The arithmetic difference between the maximum organic 
concentration indicated by the instrument and the background level 
shall be compared with the value of 500 parts per million by volume. If 
the difference is less than 500 parts per million by volume, then no 
HAP emissions are detected.
    (d) [Reserved]
    (e) Control device performance test procedures. This paragraph 
applies to the performance testing of control devices. Owners or 
operators may elect to use the alternative procedures in paragraph (f) 
of this section for performance testing of a condenser used to control 
emissions from a glycol dehydration unit process vent.
    (1) Method 1 or 1A, 40 CFR part 60, appendix A, as appropriate, 
shall be used for selection of the sampling sites at the inlet and 
outlet of the control device.
    (i) To determine compliance with the control device percent 
reduction requirement specified in Sec. 63.771(d)(1), sampling sites 
shall be located at the inlet of the control device as specified in 
paragraphs (e)(1)(i)(A) and (e)(1)(i)(B) of this section, and at the 
outlet of the control device.
    (A) The control device inlet sampling site shall be located after 
the final product recovery device.
    (B) If a vent stream is introduced with the combustion air, or as a 
secondary fuel, into a boiler or process heater with a design capacity 
less than 44 megawatts, selection of the location of the inlet sampling 
sites shall ensure the measurement of total HAP or TOC concentration, 
as applicable, in all vent streams and primary and secondary fuels.
    (ii) To determine compliance with the enclosed combustion device 
total HAP concentration limit specified in Sec. 63.771(d)(1)(i)(B), the 
sampling site shall be located at the outlet of the device.
    (2) The gas volumetric flow rate shall be determined using Method 
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
    (3) To determine compliance with the control device percent 
reduction requirement in Sec. 63.771(d)(1)(i), the owner or operator 
shall use Method 18, 40 CFR part 60, appendix A; alternatively, any 
other method or data that has been validated according to the 
applicable procedures in Method 301, 40 CFR part 63, appendix A may be 
used. The following procedures shall be used to calculate percent 
reduction efficiency:
    (i) The minimum sampling time for each run shall be 1 hour in which 
either an integrated sample or a minimum of four grab samples shall be 
taken. If grab sampling is used, then the samples shall

[[Page 6320]]

be taken at approximately equal intervals in time, such as 15 minute 
intervals during the run.
    (ii) The mass rate of either TOC (minus methane and ethane) or 
total HAP (Ei, Eo) shall be computed.
    (A) The following equations shall be used: where:
    [GRAPHIC] [TIFF OMITTED] TP06FE98.008
    
    [GRAPHIC] [TIFF OMITTED] TP06FE98.009
    
Where:

Cij, Coj= Concentration of sample component j of 
the gas stream at the inlet and outlet of the control device, 
respectively, dry basis, parts per million by volume.
Ei, Eo = Mass rate of TOC (minus methane and 
ethane) or total HAP at the inlet and outlet of the control device, 
respectively, dry basis, kilogram per hour.
Mij, Moj = Molecular weight of sample component j 
of the gas stream at the inlet and outlet of the control device, 
respectively, gram/gram-mole.
Qi, Qo = Flow rate of gas stream at the inlet and 
outlet of the control device, respectively, dry standard cubic meter 
per minute.
K2 =Constant, 2.494 x 10-6 (parts per million) 
(gram-mole per standard cubic meter) (kilogram/gram) (minute/hour), 
where standard temperature (gram-mole per standard cubic meter) is 
20 deg.C.
    (B) When the TOC mass rate is calculated, all organic compounds 
(minus methane and ethane) measured by Method 18, 40 CFR part 60, 
appendix A shall be summed using the equation in paragraph 
(e)(3)(ii)(A) of this section.
    (C) When the total HAP mass rate is calculated, only HAP chemicals 
listed in Table 1 of this subpart shall be summed using the equation in 
paragraph (e)(3)(ii)(A) of this section.
    (iii) The percent reduction in TOC (minus methane and ethane) or 
total HAP shall be calculated as follows
[GRAPHIC] [TIFF OMITTED] TP06FE98.010

Where:

Rcd =Control efficiency of control device, percent.
Ei =Mass rate of TOC (minus methane and ethane) or total HAP 
at the inlet to the control device as calculated under paragraph 
(e)(3)(ii) of this section, kilograms TOC per hour or kilograms HAP per 
hour.
Eo =Mass rate of TOC (minus methane and ethane) or total HAP 
at the outlet of the control device, as calculated under paragraph 
(e)(3)(ii) of this section, kilograms TOC per hour or kilograms HAP per 
hour.

    (iv) If the vent stream entering a boiler or process heater with a 
design capacity less than 44 megawatts is introduced with the 
combustion air or as a secondary fuel, the weight-percent reduction of 
total HAP or TOC (minus methane and ethane) across the device shall be 
determined by comparing the TOC (minus methane and ethane) or total HAP 
in all combusted vent streams and primary and secondary fuels with the 
TOC (minus methane and ethane) or total HAP exiting the device, 
respectively.
    (4) To determine compliance with the enclosed combustion device 
total HAP concentration limit specified in Sec. 63.771(d)(1)(i)(B), the 
owner or operator shall use Method 18, 40 CFR part 60, appendix A to 
measure either TOC (minus methane and ethane) or total HAP. 
Alternatively, any other method or data that has been validated 
according to Method 301, 40 CFR part 63, appendix A, may be used. The 
following procedures shall be used to calculate parts per million by 
volume concentration, corrected to 3 percent oxygen:
    (i) The minimum sampling time for each run shall be 1 hour, in 
which either an integrated sample or a minimum of four grab samples 
shall be taken. If grab sampling is used, then the samples shall be 
taken at approximately equal intervals in time, such as 15-minute 
intervals during the run.
    (ii) The TOC concentration or total HAP concentration shall be 
calculated according to paragraph (e)(4)(ii)(A) or (e)(4)(ii)(B) of 
this section.
    (A) The TOC concentration is the sum of the concentrations of the 
individual components and shall be computed for each run using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TP06FE98.011

Where:

CTOC = Concentration of total organic compounds minus 
methane and ethane, dry basis, parts per million by volume.
Cji = Concentration of sample component j of sample i, dry 
basis, parts per million by volume.
n = Number of components in the sample.
x = Number of samples in the sample run.

    (B) The total HAP concentration shall be computed according to the 
equation in paragraph (e)(4)(ii)(A) of this section, except that only 
HAP chemicals listed in Table 1 of this subpart shall be summed.
    (iii) The TOC concentration or total HAP concentration shall be 
corrected to 3 percent oxygen as follows:
    (A) The emission rate correction factor or excess air, integrated 
sampling and analysis procedures of Method 3B, 40 CFR part 60, appendix 
A shall be used to determine the oxygen concentration. The samples 
shall be taken during the same time that the samples are taken for 
determining TOC concentration or total HAP concentration.
    (B) The TOC or HAP concentration shall be corrected for percent 
oxygen by using the following equation:
[GRAPHIC] [TIFF OMITTED] TP06FE98.012

Where:

Cc = TOC concentration or total HAP concentration corrected to 3 
percent oxygen, dry basis, parts per million by volume.
Cm = TOC concentration or total HAP concentration, dry 
basis, parts per million by volume.
%O2d = Concentration of oxygen, dry basis, percent by 
volume.

    (f) As an alternative to the procedures in paragraph (e) of this 
section, an owner or operator may elect to use the procedures 
documented in the Gas Research Institute Report entitled, ``Atmospheric 
Rich/Lean Method for Determining Glycol Dehydrator Emissions'' (GRI-95/
0368.1).


Sec. 63.773  Inspection and monitoring requirements.

    (a) This section applies to an owner or operator using air emission 
controls in accordance with the requirements of Secs. 63.765 and 
63.766.
    (b) Cover inspection and monitoring requirements. (1) Each cover 
used in accordance with the requirements of Sec. 63.766 shall be 
visually inspected and monitored for no detectable emissions by the 
owner or operator using the procedure specified in paragraph (b)(3) of 
this section, except as provided for in paragraph (b)(2) of this 
section.
    (2) An owner or operator is exempt from performing the cover 
inspection and monitoring requirements specified in paragraph (b)(3) of 
this section for the following units:
    (i) A storage vessel internal floating roof that is inspected and 
monitored in

[[Page 6321]]

accordance with the requirements of 40 CFR 60.113b(a); or
    (ii) A storage vessel external floating roof that is inspected and 
monitored in accordance with the requirements of 40 CFR 60.113b(b).
    (iii) If a storage vessel is buried partially or entirely 
underground, an owner or operator is required to perform the cover 
inspection and monitoring requirements specified in paragraph (b)(3) of 
this section only for those portions of the storage vessel cover and 
those connections to the storage vessel cover or tank body (e.g., fill 
ports, access hatches, gauge wells, etc.) that extend to or above the 
ground surface and can be opened to the atmosphere.
    (3) Inspection and monitoring of a cover shall be performed as 
follows:
    (i) The cover and all cover openings shall be initially visually 
inspected and monitored for no detectable emissions on or before the 
date that the unit on which the cover is installed becomes subject to 
the provisions of this subpart and at other times as requested by the 
Administrator.
    (ii) At least once every six months following the initial visual 
inspection and monitoring for no detectable emissions required under 
paragraph (b)(3)(i) of this section, the owner and operator shall 
visually inspect and monitor the cover and each cover opening, except 
for following cover openings:
    (A) A cover opening that has continuously remained in a closed, 
sealed position for the entire period since the last time the cover 
opening was visually inspected and monitored for no detectable 
emissions;
    (B) A cover opening that is designated as unsafe to inspect and 
monitor in accordance with paragraph (b)(3)(v) of this section;
    (C) A cover opening on a cover installed and placed in operation 
before February 6, 1998, that is designated as difficult to inspect and 
monitor in accordance with paragraph (b)(3)(vi) of this section.
    (iii) To visually inspect a cover, the owner or operator shall view 
the entire cover surface and each cover opening in a closed, sealed 
position for evidence of any defect that may affect the ability of the 
cover or cover opening to continue to operate with no detectable 
emissions. A visible hole, gap, tear, or split in the cover surface or 
a cover opening is defined as a leak which shall be repaired in 
accordance with paragraph (b)(3)(vii) of this section.
    (iv) To monitor a cover for no detectable emissions, the owner or 
operator shall use the following procedure:
    (A) For all cover connections and seals, except for the seals 
around a rotating shaft that passes through a cover opening, if the 
monitoring instrument indicates an instrument concentration reading 
greater than 500 parts per million by volume minus the background 
level, then a leak is detected. Each detected leak shall be repaired in 
accordance with paragraph (b)(3)(vii) of this section.
    (B) For the seals around a rotating shaft that passes through a 
cover opening, if the monitoring instrument indicates an instrument 
concentration reading greater than 10,000 parts per million by volume 
then a leak is detected. Each detected leak shall be repaired in 
accordance with paragraph (b)(3)(vii) of this section.
    (v) An owner or operator may designate a cover as an unsafe to 
inspect and monitor cover if all of the following conditions are met:
    (A) The owner or operator determines that inspection or monitoring 
of the cover would expose a worker to dangerous, hazardous, or other 
unsafe conditions.
    (B) The owner or operator develops and implements a written plan 
and schedule to inspect the cover using the procedure specified in 
paragraph (b)(3)(iii) of this section and monitor the cover using the 
procedure specified in paragraph (b)(3)(iv) of this section as 
frequently as practicable during those times when a worker can safely 
access the cover.
    (vi) An owner or operator may designate a cover installed and 
placed in operation before February 6, 1998 as a difficult to inspect 
and monitor cover if all of the following conditions are met:
    (A) The owner or operator determines that inspection or monitoring 
the cover requires elevating a worker to a height greater than 2 meters 
(approximately 7 feet) above a support surface; and
    (B) The owner and operator develops and implements a written plan 
and schedule to inspect the cover using the procedure specified in 
paragraph (b)(3)(iii) of this section, and monitors the cover using the 
procedure specified in paragraph (b)(3)(iv) of this section at least 
once per calendar year.
    (vii) When a leak is detected by either of the methods specified in 
paragraph (b)(3)(iii) or (b)(3)(iv) of this section, the owner or 
operator shall make a first attempt at repairing the leak no later than 
five calendar days after the leak is detected. Repair of the leak shall 
be completed as soon as practicable, but no later than 15 calendar days 
after the leak is detected. If repair of the leak cannot be completed 
within the 15-day period, then the owner or operator shall not add 
material to the unit on which the cover is installed until the repair 
of the leak is completed.
    (c) Closed-vent system inspection and monitoring requirements. (1) 
The owner or operator shall visually inspect and monitor each closed-
vent system for no detectable emissions at the following times:
    (i) On or before the date that the unit connected to the closed-
vent system becomes subject to the provisions of this subpart;
    (ii) At least once per year after the date that the closed-vent 
system is inspected in accordance with the requirements of paragraph 
(c)(1)(i) of this section; and
    (iii) At other times as requested by the Administrator.
    (2) To visually inspect a closed-vent system, the owner or operator 
shall view the entire length of ductwork, piping and connections to 
covers and control devices for evidence of visible defects (such as 
holes in ductwork or piping and loose connections) that may affect the 
ability of the system to operate with no detectable emissions. A 
visible hole, gap, tear, or split in the closed-vent system is defined 
as a leak which shall be repaired in accordance with paragraph (c)(4) 
of this section.
    (3) To monitor a closed-vent system for no detectable emissions, 
the owner or operator shall use Method 21, 40 CFR part 60, appendix A 
to test each closed-vent system joint, seam, or other connection. For 
the annual leak detection monitoring after the initial leak detection 
monitoring, the owner or operator is not required to monitor those 
closed-vent system components which continuously operate at a pressure 
below atmospheric pressure or those closed-vent system joints, seams, 
or other connections that are permanently or semi-permanently sealed 
(e.g., a welded joint between two sections of metal pipe or a bolted 
and gasketed pipe flange).
    (4) When a leak is detected by either of the methods specified in 
paragraph (c)(2) or (c)(3) of this section, the owner or operator shall 
make a first attempt at repairing the leak no later than five calendar 
days after the leak is detected. Repair of the leak shall be completed 
as soon as practicable, but no later than 15 calendar days after the 
leak is detected.
    (d) Control device monitoring requirements. (1) For each control 
device, except as provided for in paragraph (d)(2) of this section, the 
owner or operator shall install and operate a continuous monitoring 
system in accordance with the requirements of paragraphs (d)(3) through 
(d)(5) of this

[[Page 6322]]

section. The continuous monitoring system shall be designed and 
operated so that a determination can be made on whether the control 
device is continuously achieving the applicable performance 
requirements of Sec. 63.771.
    (2) An owner or operator is exempt from the monitoring requirements 
specified in paragraphs (d)(3) through (d)(5) of this section for the 
following types of control devices:
    (i) A boiler or process heater in which all vent streams are 
introduced with primary fuel; or
    (ii) A boiler or process heater with a design heat input capacity 
equal to or greater than 44 megawatts.
    (3) The owner or operator shall install, calibrate, operate, and 
maintain a device equipped with a continuous recorder to measure the 
values of operating parameters appropriate for the control device as 
specified in either paragraph (d)(3)(i), (d)(3)(ii), or (d)(3)(iii) of 
this section. The monitoring equipment shall be installed, calibrated, 
and maintained in accordance with the equipment manufacturer's 
specifications or other written procedures that provide adequate 
assurance that the equipment would reasonably be expected to monitor 
accurately. The continuous recorder shall be a data recording device 
that either records an instantaneous data value at least once every 15 
minutes or records 15-minute or more frequent block average values. The 
owner or operator shall use any of the following continuous monitoring 
systems:
    (i) A continuous monitoring system that measures the following 
operating parameters as applicable:
    (A) For a thermal vapor incinerator, a temperature monitoring 
device equipped with a continuous recorder. The monitoring device shall 
have an accuracy of 1 percent of the temperature being 
monitored in  deg.C, or 0.5 deg.C, whichever value is 
greater. The temperature sensor shall be installed at a location in the 
combustion chamber downstream of the combustion zone.
    (B) For a catalytic vapor incinerator, a temperature monitoring 
device equipped with a continuous recorder. The device shall be capable 
of monitoring temperature at two locations and have an accuracy of 
1 percent of the temperature being monitored in  deg.C, or 
0.5 deg.C, whichever value is greater. One temperature 
sensor shall be installed in the vent stream at the nearest feasible 
point to the catalyst bed inlet and a second temperature sensor shall 
be installed in the vent stream at the nearest feasible point to the 
catalyst bed outlet.
    (C) For a flare, a heat sensing monitoring device equipped with a 
continuous recorder that indicates the continuous ignition of the pilot 
flame.
    (D) For a boiler or process heater with a design heat input 
capacity of less than 44 megawatts, a temperature monitoring device 
equipped with a continuous recorder. The temperature monitoring device 
shall have an accuracy of 1 percent of the temperature 
being monitored in  deg.C, or 0.5 deg.C, whichever value is 
greater. The temperature sensor shall be installed at a location in the 
combustion chamber downstream of the combustion zone.
    (E) For a condenser, a temperature monitoring device equipped with 
a continuous recorder. The temperature monitoring device shall have an 
accuracy of 1 percent of the temperature being monitored in 
 deg.C, or 0.5 deg.C, whichever value is greater. The 
temperature sensor shall be installed at a location in the exhaust vent 
stream from the condenser.
    (F) For a regenerative-type carbon adsorption system, an 
integrating regeneration stream flow monitoring device equipped with a 
continuous recorder and a carbon bed temperature monitoring device 
equipped with a continuous recorder. The integrating regeneration 
stream flow monitoring device shall have an accuracy of 10 
percent and measure the total regeneration stream mass flow during the 
carbon bed regeneration cycle. The temperature monitoring device shall 
have an accuracy of 1 percent of the temperature being 
monitored in  deg.C, or 0.5 deg.C, whichever value is 
greater and measure the carbon bed temperature after regeneration and 
within 15 minutes of completing the cooling cycle and the duration of 
the carbon bed steaming cycle.
    (ii) A continuous monitoring system that measures the concentration 
level of organic compounds in the exhaust vent stream from the control 
device using an organic monitoring device equipped with a continuous 
recorder.
    (iii) A continuous monitoring system that measures alternative 
operating parameters other than those specified in paragraph (d)(3)(i) 
or (d)(3)(ii) of this section upon approval of the Administrator as 
specified in Sec. 63.8(f)(1) through (f)(5).
    (4) For each operating parameter monitored in accordance with the 
requirements of paragraph (d)(3) of this section, the owner or operator 
shall establish a minimum operating parameter value or a maximum 
operating parameter value, as appropriate for the control device, to 
define the conditions at which the control device must be operated to 
continuously achieve the applicable performance requirements of 
Sec. 63.771. Each minimum or maximum operating parameter value shall be 
established as follows:
    (i) If the owner or operator conducts performance tests in 
accordance with the requirements of Sec. 63.771 to demonstrate that the 
control device achieves the applicable performance requirements 
specified in Sec. 63.771, then the minimum operating parameter value or 
the maximum operating parameter value shall be established based on 
values measured during the performance test and supplemented, as 
necessary, by control device design analysis and manufacturer 
recommendations.
    (ii) If the owner or operator uses control device design analysis 
in accordance with the requirements of Sec. 63.771(d)(3)(iv) to 
demonstrate that the control device achieves the applicable performance 
requirements specified in Sec. 63.771(d)(1), then the minimum operating 
parameter value or the maximum operating parameter value shall be 
established based on the control device design analysis and the control 
device manufacturer's recommendations.
    (5) The owner or operator shall regularly inspect the data recorded 
by the continuous monitoring system to determine whether the control 
device is operating in accordance with the applicable requirements of 
Sec. 63.771(d).


Sec. 63.774  Recordkeeping requirements.

    (a) The recordkeeping provisions of 40 CFR part 63, subpart A that 
apply and those that do not apply to owners and operators of sources 
subject to this subpart are listed in Table 2 of this subpart.
    (b) Except as specified in paragraphs (c) and (d) of this section, 
each owner or operator of a source subject to this subpart shall 
maintain the records specified in paragraphs (b)(1) and (b)(2) of this 
section in accordance with the requirements of Sec. 63.10(b)(1) 
(General Provisions):
    (1) Records specified in Sec. 63.10(b)(2);
    (2) Records specified in Sec. 63.10(c) for each monitoring system 
operated by the owner or operator in accordance with the requirements 
of Sec. 63.773(d).
    (c) The owner or operator of an area source subject to the control 
requirements for triethylene glycol dehydration unit process vents in 
Sec. 63.765 is exempt from the requirements of Sec. 63.6(e)(3) and 
Sec. 63.10(b)(2)(iv) and (b)(2)(v).
    (d) An owner or operator that is exempt from control requirements

[[Page 6323]]

under Sec. 63.764(e) shall maintain a record of the design capacity (in 
terms of natural gas flow rate to the unit per day) of each glycol 
dehydration unit that is not controlled according to the requirements 
of Sec. 63.764(c)(1)(i) and (d)(1).


Sec. 63.775  Reporting requirements.

    (a) The reporting provisions of 40 CFR part 63, subpart A that 
apply and those that do not apply to owners and operators of sources 
subject to these subparts are listed in Table 2 of this subpart.
    (b) Each owner or operator of a major source subject to this 
subpart shall submit the following reports to the Administrator:
    (1) An Initial Notification described in Sec. 63.9(a) through (d), 
except that the notification required by Sec. 63.9(b)(2) shall be 
submitted not later than one year after the effective date of this 
standard.
    (2) A Notification of Performance Tests specified in Secs. 63.7 and 
63.9(e) and (g).
    (3) A Notification of Compliance Status specified in Sec. 63.9(h).
    (4) Performance test reports specified in Sec. 63.10(d)(2) and 
performance evaluation reports specified in Sec. 63.10(e)(2). Separate 
performance evaluation reports as described in Sec. 63.10(e)(2) are not 
required if the information is included in the report specified in 
paragraph (b)(6) of this section.
    (5) Startup, shutdown, and malfunction reports specified in 
Sec. 63.10(d)(5) shall be submitted as required. Separate startup, 
shutdown, or malfunction reports as described in Sec. 63.10(d)(5) are 
not required if the information is included in the report specified in 
paragraph (b)(6) of this section.
    (6) The excess emission and CMS performance report and summary 
report specified in Sec. 63.10(e)(3) shall be submitted on a semi-
annual basis (i.e., once every 6-month period). The summary report 
shall be entitled ``Summary Report--Gaseous Excess Emissions and 
Continuous Monitoring System Performance.''
    (7) The owner or operator shall meet the requirements specified in 
paragraph (b) of this section for any emission point or material that 
becomes subject to the standards in this subpart due to an increase in 
flow, concentration, or other parameters equal to or greater than the 
limits specified in this subpart.
    (8) For each control device other than a flare used to meet the 
requirements of this subpart, the owner or operator shall submit the 
following information for each operating parameter required to be 
monitored in accordance with the requirements of Sec. 63.773(d):
    (i) The minimum operating parameter value or maximum operating 
parameter value, as appropriate for the control device, established by 
the owner or operator to define the conditions at which the control 
device must be operated to continuously achieve the applicable 
performance requirements of Sec. 63.771(d)(1).
    (ii) An explanation of the rationale for why the owner or operator 
selected each of the operating parameter values established in 
paragraph (d)(1) of this section. This explanation shall include any 
data and calculations used to develop the value and a description of 
why the chosen value indicates that the control device is operating in 
accordance with the applicable requirements of Sec. 63.771(d)(1).
    (9) Each owner or operator of a major source subject to this 
subpart that is not subject to the control requirements for glycol 
dehydration unit process vents in Sec. 63.765 is exempt from all 
reporting requirements for major sources in this subpart.
    (c) Each owner or operator of an area source subject to the control 
requirements of this subpart for triethylene glycol dehydration unit 
process vents in Sec. 63.765 shall submit the following reports to the 
Administrator:
    (1) An Initial Notification described in Sec. 63.9 (a) through (d), 
except that the notification required by Sec. 63.9(b)(2) shall be 
submitted not later than one year after the effective date of this 
standard.
    (2) A Notification of Performance Tests specified in Secs. 63.7 and 
63.9 (e) and (g).
    (3) A Notification of Compliance Status specified in Sec. 63.9(h).
    (4) Performance test reports specified in Sec. 63.10(d)(2) and 
performance evaluation reports specified in Sec. 63.10(e)(2). Separate 
performance evaluation reports as described in Sec. 63.10(e)(2) are not 
required if the information is included in the report specified in 
paragraph (c)(6) of this section.
    (5) A report describing any malfunctions that are not corrected 
within two calendar days of the malfunction, to be submitted within 
seven calendar days of the uncorrected malfunction.
    (6) A summary report as specified in Sec. 63.10(e)(3) shall be 
submitted on an annual basis (i.e., once every 12-month period). The 
summary report shall be entitled ``Summary Report--Gaseous Excess 
Emissions and Continuous Monitoring System Performance.''
    (7) The owner or operator shall meet the requirements specified in 
this paragraph for any emission point or material that becomes subject 
to the standards in this subpart due to an increase in flow or 
concentration mass parameters equal to or greater than the limits 
specified in Sec. 63.764 (b), (c), or (d).
    (8) For each control device other than a flare used to meet the 
requirements of this subpart, the owner or operator shall submit the 
following information for each operating parameter required to be 
monitored in accordance with the requirements of Sec. 63.773(d):
    (i) The minimum operating parameter value or maximum operating 
parameter value, as appropriate for the control device, established by 
the owner or operator to define the conditions at which the control 
device must be operated to continuously achieve the applicable 
performance requirements of Sec. 63.771(d)(1).
    (ii) An explanation of the rationale for why the owner or operator 
selected each of the operating parameter values established in 
paragraph (d)(1) of this section. This explanation shall include any 
data and calculations used to develop the value and a description of 
why this value indicates that the control device is operating in 
accordance with the applicable requirements of Sec. 63.771(d)(1).
    (9) Each owner or operator of an area source subject to this 
subpart that is not subject to the control requirements for glycol 
dehydration unit process vents in Sec. 63.765 is exempt from all 
reporting requirements in this subpart.


Sec. 63.776  Delegation of authority [Reserved]


Sec. 63.777  Alternative means of emission limitation.

    (a) If, in the judgment of the Administrator, an alternative means 
of emission limitation will achieve a reduction in HAP emissions at 
least equivalent to the reduction in HAP emissions from that source 
achieved under the applicable requirements in Secs. 63.764 through 
63.771, the Administrator will publish in the Federal Register a notice 
permitting the use of the alternative means for purposes of compliance 
with that requirement. The notice may condition the permission on 
requirements related to the operation and maintenance of the 
alternative means.
    (b) Any notice under paragraph (a) of this section shall be 
published only after public notice and an opportunity for a hearing.

[[Page 6324]]

    (c) Any person seeking permission to use an alternative means of 
compliance under this section shall collect, verify, and submit to the 
Administrator information demonstrating that the alternative achieves 
equivalent emission reductions.


Sec. 63.778  [Reserved]


Sec. 63.779  [Reserved]

 Table 1 to Subpart HH.--List of Hazardous Air Pollutants for Subpart HH
------------------------------------------------------------------------
            CAS Number a                         Chemical name          
------------------------------------------------------------------------
75070...............................  Acetaldehyde.                     
71432...............................  Benzene (includes benzene in      
                                       gasoline).                       
75150...............................  Carbon disulfide.                 
463581..............................  Carbonyl sulfide.                 
100414..............................  Ethyl benzene.                    
107211..............................  Ethylene glycol.                  
50000...............................  Formaldehyde.                     
110543..............................  n-Hexane.                         
91203...............................  Naphthalene.                      
108883..............................  Toluene.                          
540841..............................  2,2,4-Trimethylpentane.           
1330207.............................  Xylenes (isomers and mixture).    
95476...............................  o-Xylene.                         
108383..............................  m-Xylene.                         
106423..............................  p-Xylene.                         
------------------------------------------------------------------------
a CAS numbers refer to the Chemical Abstracts Services registry number  
  assigned to specific compounds, isomers, or mixtures of compounds.    


            Table 2 to Subpart HH.--Applicability of 40 CFR Part 63 General Provisions to Subpart HH            
----------------------------------------------------------------------------------------------------------------
      General provisions reference          Applicable to subpart HH                    Comment                 
----------------------------------------------------------------------------------------------------------------
Sec.  63.1(a)(1)........................  Yes........................                                           
Sec.  63.1(a)(2)........................  Yes........................                                           
Sec.  63.1(a)(3)........................  Yes........................                                           
Sec.  63.1(a)(4)........................  Yes........................                                           
Sec.  63.1(a)(5)........................  No.........................  Section reserved.                        
Sec.  63.1(a)(6)-(a)(8).................  Yes........................                                           
Sec.  63.1(a)(9)........................  No.........................  Section reserved.                        
Sec.  63.1(a)(10).......................  Yes........................                                           
Sec.  63.1(a)(11).......................  Yes........................                                           
Sec.  63.1(a)(12)-(a)(14)...............  Yes........................                                           
Sec.  63.1(b)(1)........................  No.........................  Subpart HH specifies applicability.      
Sec.  63.1(b)(2)........................  Yes........................                                           
Sec.  63.1(b)(3)........................  No.........................                                           
Sec.  63.1(c)(1)........................  No.........................  Subpart HH specifies applicability.      
Sec.  63.1(c)(2)........................  Yes........................  Unless required by the State, area       
                                                                        sources subject to subpart HH are       
                                                                        exempted from permitting requirements.  
Sec.  63.1(c)(3)........................  No.........................  Section reserved.                        
Sec.  63.1(c)(4)........................  Yes........................                                           
Sec.  63.1(c)(5)........................  Yes........................                                           
Sec.  63.1(d)...........................  No.........................  Section reserved.                        
Sec.  63.1(e)...........................  Yes........................                                           
Sec.  63.2..............................  Yes........................  Except definition of major source is     
                                                                        unique for this source category and     
                                                                        there are additional definitions in     
                                                                        subpart HH.                             
Sec.  63.3(a)-(c).......................  Yes........................                                           
Sec.  63.4(a)(1)-(a)(3).................  Yes........................                                           
Sec.  63.4(a)(4)........................  No.........................  Section reserved.                        
Sec.  63.4(a)(5)........................  Yes........................                                           
Sec.  63.4(b)...........................  Yes........................                                           
Sec.  63.4(c)...........................  Yes........................                                           
Sec.  63.5(a)(1)........................  Yes........................                                           
Sec.  63.5(a)(2)........................  No.........................  Preconstruction review required only for 
                                                                        major sources that commence construction
                                                                        after promulgation of the standard.     
Sec.  63.5(b)(1)........................  Yes........................                                           
Sec.  63.5(b)(2)........................  No.........................  Section reserved.                        
Sec.  63.5(b)(3)........................  Yes........................                                           
Sec.  63.5(b)(4)........................  Yes........................                                           
Sec.  63.5(b)(5)........................  Yes........................                                           
Sec.  63.5(b)(6)........................  Yes........................                                           
Sec.  63.5(c)...........................  No.........................  Section reserved.                        
Sec.  63.5(d)(1)........................  Yes........................                                           
Sec.  63.5(d)(2)........................  Yes........................                                           
Sec.  63.5(d)(3)........................  Yes........................                                           
Sec.  63.5(d)(4)........................  Yes........................                                           
Sec.  63.5(e)...........................  Yes........................                                           
Sec.  63.5(f)(1)........................  Yes........................                                           
Sec.  63.5(f)(2)........................  Yes........................                                           
Sec.  63.6(a)...........................  Yes........................                                           
Sec.  63.6(b)(1)........................  Yes........................                                           
Sec.  63.6(b)(2)........................  Yes........................                                           
Sec.  63.6(b)(3)........................  Yes........................                                           
Sec.  63.6(b)(4)........................  Yes........................                                           

[[Page 6325]]

                                                                                                                
Sec.  63.6(b)(5)........................  Yes........................                                           
Sec.  63.6(b)(6)........................  No.........................  Section reserved.                        
Sec.  63.6(b)(7)........................  Yes........................                                           
Sec.  63.6(c)(1)........................  Yes........................                                           
Sec.  63.6(c)(2)........................  Yes........................                                           
Sec.  63.6(c)(3)-(c)(4).................  No.........................  Sections reserved.                       
Sec.  63.6(c)(5)........................  Yes........................                                           
Sec.  63.6(d)...........................  No.........................  Section reserved.                        
Sec.  63.6(e)...........................  Yes/No.....................  Area sources exempt from paragraph       
                                                                        (e)(3).                                 
Sec.  63.6(f)(1)........................  Yes........................                                           
Sec.  63.6(f)(2)........................  Yes........................                                           
Sec.  63.6(f)(3)........................  Yes........................                                           
Sec.  63.6(g)...........................  Yes........................                                           
Sec.  63.6(h)...........................  No.........................  Subpart HH does not require continuous   
                                                                        emissions monitoring systems.           
Sec.  63.6(i)(1)-(i)(14)................  Yes........................                                           
Sec.  63.6(i)(15).......................  No.........................  Section reserved.                        
Sec.  63.6(i)(16).......................  Yes........................                                           
Sec.  63.6(j)...........................  Yes........................                                           
Sec.  63.7(a)(1)........................  Yes........................                                           
Sec.  63.7(a)(2)........................  Yes........................                                           
Sec.  63.7(a)(3)........................  Yes........................                                           
Sec.  63.7(b)...........................  Yes........................                                           
Sec.  63.7(c)...........................  Yes........................                                           
Sec.  63.7(d)...........................  Yes........................                                           
Sec.  63.7(e)(1)........................  Yes........................                                           
Sec.  63.7(e)(2)........................  Yes........................                                           
Sec.  63.7(e)(3)........................  Yes........................                                           
Sec.  63.7(e)(4)........................  Yes........................                                           
Sec.  63.7(f)...........................  Yes........................                                           
Sec.  63.7(g)...........................  Yes........................                                           
Sec.  63.7(h)...........................  Yes........................                                           
Sec.  63.8(a)(1)........................  Yes........................                                           
Sec.  63.8(a)(2)........................  Yes........................                                           
Sec.  63.8(a)(3)........................  No.........................  Section reserved.                        
Sec.  63.8(a)(4)........................  Yes........................                                           
Sec.  63.8(b)(1)........................  Yes........................                                           
Sec.  63.8(b)(2)........................  Yes........................                                           
Sec.  63.8(b)(3)........................  Yes........................                                           
Sec.  63.8(c)(1)........................  Yes........................                                           
Sec.  63.8(c)(2)........................  Yes........................                                           
Sec.  63.8(c)(3)........................  Yes........................                                           
Sec.  63.8(c)(4)........................  No.........................                                           
Sec.  63.8(c)(5)-(c)(8).................  Yes........................                                           
Sec.  63.8(d)...........................  Yes........................                                           
Sec.  63.8(e)...........................  Yes........................                                           
Sec.  63.8(f)(1)-(f)(5).................  Yes........................                                           
Sec.  63.8(f)(6)........................  No.........................  Subpart HH does not require continuous   
                                                                        emissions monitoring.                   
Sec.  63.8(g)...........................  No.........................  Subpart HH specifies continuous          
                                                                        monitoring system data reduction        
                                                                        requirements.                           
Sec.  63.9(a)...........................  Yes........................                                           
Sec.  63.9(b)(1)........................  Yes........................                                           
Sec.  63.9(b)(2)........................  Yes........................  Sources are given one year (rather than  
                                                                        120 days) to submit this notification.  
Sec.  63.9(b)(3)........................  Yes........................                                           
Sec.  63.9(b)(4)........................  Yes........................                                           
Sec.  63.9(b)(5)........................  Yes........................                                           
Sec.  63.9(c)...........................  Yes........................                                           
Sec.  63.9(d)...........................  Yes........................                                           
Sec.  63.9(e)...........................  Yes........................                                           
Sec.  63.9(f)...........................  No.........................                                           
Sec.  63.9(g)...........................  Yes........................                                           
Sec.  63.9(h)(1)-(h)(3).................  Yes........................                                           
Sec.  63.9(h)(4)........................  No.........................  Section reserved.                        
Sec.  63.9(h)(5)-(h)(6).................  Yes........................                                           
Sec.  63.9(i)...........................  Yes........................                                           
Sec.  63.9(j)...........................  Yes........................                                           
Sec.  63.10(a)..........................  Yes........................                                           
Sec.  63.10(b)(1).......................  Yes........................                                           
Sec.  63.10(b)(2).......................  Yes/No.....................  Area sources are exempt from paragraphs  
                                                                        (b)(2)(iv) and (v).                     
Sec.  63.10(b)(3).......................  No.........................                                           
Sec.  63.10(c)(1).......................  Yes........................                                           
Sec.  63.10(c)(2)-(c)(4)................  No.........................  Sections reserved.                       
Sec.  63.10(c)(5)-(c)(8)................  Yes........................                                           
Sec.  63.10(c)(9).......................  No.........................  Section reserved.                        

[[Page 6326]]

                                                                                                                
Sec.  63.10(c)(10)-(c)(15)..............  Yes........................                                           
Sec.  63.10(d)(1).......................  Yes........................                                           
Sec.  63.10(d)(2).......................  Yes........................                                           
Sec.  63.10(d)(3).......................  Yes........................                                           
Sec.  63.10(d)(4).......................  Yes........................                                           
Sec.  63.10(d)(5).......................  Yes/No.....................  Subpart HH requires major sources to     
                                                                        submit a startup, shutdown and          
                                                                        malfunction report semi-annually; area  
                                                                        sources are exempt.                     
Sec.  63.10(e)..........................  Yes/No.....................  Subpart HH requires major sources to     
                                                                        submit continuous monitoring system     
                                                                        performance reports semi-annually; area 
                                                                        sources are required to send these      
                                                                        reports annually.                       
Sec.  63.10(f)..........................  Yes........................                                           
Sec.  63.11(a)-(b)......................  Yes........................                                           
Sec.  63.12(a)-(c)......................  Yes........................                                           
Sec.  63.13(a)-(c)......................  Yes........................                                           
Sec.  63.14(a)-(b)......................  Yes........................                                           
Sec.  63.15(a)-(b)......................  Yes........................                                           
----------------------------------------------------------------------------------------------------------------

    B. Part 63 is amended by adding subpart HHH to read as follows:
Subpart HHH--National Emission Standards for Hazardous Air Pollutants 
from Natural Gas Transmission and Storage Facilities
Sec.
63.1270  Applicability and designation of affected source.
63.1271  Definitions.
63.1272  [Reserved]
63.1273  [Reserved]
63.1274  General standards.
63.1275  Glycol dehydration unit process vent standards.
63.1276  [Reserved]
63.1277  [Reserved]
63.1278  [Reserved]
63.1279  [Reserved]
63.1280  [Reserved]
63.1281  Control equipment requirements.
63.1282  Test methods and compliance procedures.
63.1283  Inspection and monitoring requirements.
63.1284  Recordkeeping requirements.
63.1285  Reporting requirements.
63.1286  Delegation of authority. [Reserved]
63.1287  Alternative means of emission limitation.
63.1288  [Reserved]
63.1289  [Reserved]
Table 1 to Subpart HHH--List of Hazardous Air Pollutants (HAP) for 
Subpart HHH
Table 2 to Subpart HHH--Applicability of 40 CFR Part 63 General 
Provisions to Subpart HHH

Subpart HHH--National Emission Standards for Hazardous Air 
Pollutants From Natural Gas Transmission and Storage Facilities


Sec. 63.1270  Applicability and designation of affected source.

    (a) This subpart applies to owners or operators of natural gas 
transmission and storage facilities that transport or store natural gas 
prior to entering the pipeline to a local distribution company or to a 
final end user and that are major sources of hazardous air pollutant 
(HAP) emissions.
    (b) The affected source is each glycol dehydration unit.
    (c) The owner or operator of a facility that does not contain an 
affected source, as specified in paragraph (b) of this section, is not 
subject to the requirements of this subpart.
    (d) The owner or operator of each affected source shall achieve 
compliance with the provisions of this subpart by the following dates:
    (1) The owner or operator of an affected source the construction or 
reconstruction of which commenced before February 6, 1998, shall 
achieve compliance with the provisions of the subpart as expeditiously 
as practical after [the date of publication of the final rule], but no 
later than three years after [the date of publication of the final 
rule] except as provided for in Sec. 63.6(i).
    (2) The owner or operator of an affected source the construction or 
reconstruction of which commences on or after February 6, 1998, shall 
achieve compliance with the provisions of this subpart immediately upon 
startup or [the date of publication of the final rule], whichever date 
is later.
    (e) An owner or operator of an affected source that is a major 
source or located at a major source and is subject to the provisions of 
this subpart is also subject to 40 CFR part 70 permitting requirements.


Sec. 63.1271  Definitions.

    All terms used in this subpart shall have the meaning given to them 
in the Clean Air Act, subpart A of this part (General Provisions), and 
in this section. If the same term is defined in subpart A and in this 
section, it shall have the meaning given in this section for purposes 
of this subpart.
    Associated equipment, as used in this subpart and as referred to in 
section 112(n)(4) of the Act, means equipment associated with an oil or 
natural gas exploration or production well, and includes all equipment 
from the wellbore to the point of custody transfer, except glycol 
dehydration units and storage vessels with the potential for flash 
emissions.
    Average concentration, as used in this subpart, means the flow-
weighted annual average concentration, as determined according to the 
procedures specified in Sec. 63.1282(a).
    Boiler means any enclosed combustion device that extracts useful 
energy in the form of steam and is not an incinerator.
    Closed-vent system means a system that is not open to the 
atmosphere and is composed of piping, ductwork, connections, and, if 
necessary, flow inducing devices that transport gas or vapor from an 
emission point to a control device or back into the process. If gas or 
vapor from regulated equipment is routed to a process (e.g., to a fuel 
gas system), the process shall not be considered a closed vent system 
and is not subject to closed vent system standards.
    Combustion device means an individual unit of equipment, such as a 
flare, incinerator, process heater, or boiler, used for the combustion 
of volatile organic compound vapors.
    Compressor station means any permanent combination of equipment 
that supplies energy to move natural gas at increased pressure from 
fields, in transmission pipelines, or into storage.
    Continuous recorder means a data recording device that either 
records an instantaneous data value at least once every 15 minutes or 
records 15-minute or more frequent block average values.

[[Page 6327]]

    Control device means any equipment used for recovering or oxidizing 
hazardous air pollutant (HAP) and volatile organic compound (VOC) 
vapors. Such equipment includes, but is not limited to, absorbers, 
carbon adsorbers, condensers, incinerators, flares, boilers, and 
process heaters. For the purposes of this subpart, if gas or vapor from 
regulated equipment is used, reused, returned back to the process, or 
sold, then the recovery system used, including piping, connections, and 
flow inducing devices, is not considered to be control devices.
    Facility means any grouping of equipment where natural gas is 
processed, compressed, or stored prior to entering a pipeline to a 
local distribution company or to a final end user. A facility for this 
source category typically is: A natural gas compressor station that 
receives natural gas via pipeline, from an underground natural gas 
storage operation, from a condensate tank battery, or from a natural 
gas processing plant; or An underground natural gas storage operation. 
The emission points associated with these phases include, but are not 
limited to, process vents. Processes that may have vents include, but 
are not limited to, dehydration, and compressor station engines. 
Facility, for the purpose of a major source determination, means 
natural gas transmission and storage equipment that is located inside 
the boundaries of an individual surface site connected by ancillary 
equipment, such as gas flow lines, roads, or power lines. Equipment 
that is part of a facility will typically be located within close 
proximity to other equipment located at the same facility. Natural gas 
transmission and storage equipment or groupings of equipment located on 
different gas leases, mineral fee tracts, lease tracts, subsurface unit 
areas, surface fee tracts, or surface lease tracts shall not be 
considered part of the same facility.
    Flame zone means the portion of the combustion chamber in a boiler 
occupied by the flame envelope.
    Flow indicator means a device which indicates whether gas flow is 
present in a line.
    Gas-condensate-glycol (GCG) separator means a two-or three-phase 
separator through which the ``rich'' glycol stream of a glycol 
dehydration unit is passed to remove entrained gas and hydrocarbon 
liquid. The GCG separator is commonly referred to as a flash separator 
or flash tank.
    Glycol dehydration unit means a device in which a liquid glycol 
directly contacts a natural gas stream (that is circulated counter 
current to the glycol flow) and absorbs water vapor in a contact tower 
or absorption column (absorber). The glycol contacts and absorbs water 
vapor and other gas stream constituents from the natural gas and 
becomes ``rich'' glycol. This glycol is then regenerated by distilling 
the water and other gas stream constituents in the glycol dehydration 
unit reboiler. The distilled or ``lean'' glycol is then recycled back 
to the absorber.
    Glycol dehydration unit reboiler vent means the vent through which 
exhaust from the reboiler of a glycol dehydration unit passes from the 
reboiler to the atmosphere.
    Glycol dehydration unit process vent means either the glycol 
dehydration unit reboiler vent or the vent from the GCG separator 
(flash tank).
    Hazardous air pollutants or HAP means the chemical compounds listed 
in section 112(b) of the Act. All chemical compounds listed in section 
112(b) of the Act need to be considered when making a major source 
determination. Only the HAP compounds listed in Table 1 of this subpart 
need to be considered when determining applicability and compliance.
    Incinerator means an enclosed combustion device that is used for 
destroying organic compounds. Auxiliary fuel may be used to heat waste 
gas to combustion temperatures. Any energy recovery section shall not 
be physically formed into one manufactured or assembled unit with the 
combustion section; rather, the energy recovery section shall be a 
separate section following the combustion section and the two are 
joined by ducts or connections carrying flue gas. The above energy 
recovery section limitation does not apply to an energy recovery 
section used solely to permit the incoming vent stream or combustion 
air.
    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) and emissions from any pipeline 
compressor or pump station shall not be aggregated with emissions from 
other similar units, whether or not such units are in a contiguous area 
or under common control; and
    (2) Emissions from processes, operations, and equipment that are 
not part of the same facility, as defined in this section, shall not be 
aggregated.
    Natural gas means the gaseous mixture of hydrocarbon gases and 
vapors, primarily consisting of methane, ethane, propane, butane, 
pentane, and hexane, along with water vapor and other constituents.
    Natural gas transmission means the pipelines used for the long 
distance transport of natural gas (excluding processing). Specific 
equipment used in natural gas transmission includes the land, mains, 
valves, meters, boosters, regulators, storage vessels, dehydrators, 
compressors, and their driving units and appurtenances, and equipment 
used for transporting gas from a production plant, delivery point of 
purchased gas, gathering system, storage area, or other wholesale 
source of gas to one or more distribution area(s).
    No detectable emissions means no escape of hazardous air pollutants 
(HAP) from a device or system to the atmosphere as determined by:
    (1) Testing the device or system in accordance with the 
requirements of Sec. 63.1282(d); and
    (2) No visible openings or defects in the device or system such as 
rips, tears, or gaps.
    Operating parameter value means a minimum or maximum value 
established for a control device or process parameter which, if 
achieved by itself or in combination with one or more other operating 
parameter values, determines that an owner or operator has complied 
with an applicable emission limitation or standard.
    Operating permit means a permit required by 40 CFR part 70 or part 
71.
    Organic monitoring device means a unit of equipment used to 
indicate the concentration level of organic compounds exiting a 
recovery device based on a detection principle such as infra-red, 
photoionization, or thermal conductivity.
    Point of material entry means at the point where a material first 
enters a source subject to this subpart.
    Primary fuel means the fuel that provides the principal heat input 
(i.e., more than 50-percent) to the device. To be considered primary, 
the fuel must be able to sustain operation without the addition of 
other fuels.
    Process heater means a device that transfers heat liberated by 
burning fuel directly to process streams or to heat transfer liquids 
other than water.
    Safety device means a device that is not used for planned or 
routine venting of liquids, gases, or fumes from the unit or equipment 
on which the device is installed; and the device remains in a closed, 
sealed position at all times except when an unplanned event requires 
that the device open for the purpose of preventing physical damage or 
permanent deformation of the unit or equipment on which the device is 
installed in accordance with good

[[Page 6328]]

engineering and safety practices for handling flammable, combustible, 
explosive, or other hazardous materials. Examples of unplanned events 
which may require a safety device to open include failure of an 
essential equipment component or a sudden power outage.
    Storage vessel means a tank or other vessel that is designed to 
contain an accumulation of crude oil, condensate, intermediate 
hydrocarbon liquids, or produced water and constructed primarily of 
non-earthen materials (e.g., wood, concrete, steel, plastic) that 
provide structural support.
    Temperature monitoring device means a unit of equipment used to 
monitor temperature and having an accuracy of 1 percent of 
the temperature being monitored expressed in  deg.C, or 
0.5 deg.C, whichever is greater.
    Total organic compounds or TOC, as used in this subpart, means 
those compounds measured according to the procedures of Method 18, 40 
CFR part 60, appendix A.
    Underground storage means the subsurface facilities utilized for 
storing natural gas that has been transferred from its original 
location for the primary purpose of load balancing, which is the 
process of equalizing the receipt and delivery of natural gas. 
Processes and operations that may be located at an underground storage 
facility include, but are not limited to, compression and dehydration.


Sec. 63.1272  [Reserved]


Sec. 63.1273  [Reserved]


Sec. 63.1274  General standards.

    (a) The owner or operator of an affected source (i.e., glycol 
dehydration unit) located at an existing or new major source of HAP 
emissions shall comply with the requirements in this subpart as 
follows:
    (1) The control requirements for glycol dehydration unit process 
vents specified in Sec. 63.1275,
    (2) The monitoring requirements of Sec. 63.1283, and
    (3) The recordkeeping and reporting requirements of Secs. 63.1284 
and 63.1285.
    (b) The owner or operator is exempt from the requirements of 
paragraph (a) of this section if the actual annual average flow of 
natural gas to the glycol dehydration unit is less than 85 thousand 
cubic meters per day (3.0 million standard cubic feet per day) or 
emissions of benzene from the unit to the atmosphere are less than 0.9 
megagram per year (1 ton per year). The flow of gas to the unit and 
emissions of benzene from the unit shall be determined by the 
procedures specified in Sec. 63.1282(a). This determination must be 
made available to the Administrator upon request.
    (c) Each owner or operator of a major HAP source subject to this 
subpart is required to apply for a part 70 or part 71 operating permit 
from the appropriate permitting authority. If the Administrator has 
approved a State operating permit program under 40 CFR part 70, the 
permit shall be obtained from the State authority. If the State 
operating permit program has not been approved, the owner or operator 
of a source shall apply to the EPA Regional Office pursuant to 40 CFR 
part 71.
    (d) An owner or operator of an affected source that is a major 
source or located at a major source subject to the provisions of this 
subpart that is in violation of an operating parameter value is in 
violation of the applicable emission limitation or standard.


Sec. 63.1275  Glycol dehydration unit process vents standards.

    (a) This section applies to each glycol dehydration unit process 
vent required to meet the air emission control requirements specified 
in Sec. 63.1274(a).
    (b) Except as provided in paragraph (c) of this section, the 
following air emission control requirements apply to glycol dehydration 
unit process vents at an existing or new source.
    (1) For each glycol dehydration unit process vent, the owner or 
operator shall control air emissions by connecting the process vent 
through a closed-vent system to a control device designed and operated 
in accordance with the requirements of Sec. 63.1281(c) and (d).
    (2) One or more safety devices that vent directly to the atmosphere 
may be used on the air emission control equipment complying with 
paragraph (b)(1) of this section.
    (c) As an alternative to the requirements of paragraph (b) of this 
section, the owner or operator may comply with one of the following:
    (1) The owner or operator shall control air emissions by connecting 
the process vent to a process natural gas line through a closed-vent 
system designed and operated in accordance with the requirements of 
Sec. 63.1281(c) and (d).
    (2) The owner or operator shall demonstrate, to the Administrator's 
satisfaction, that total HAP emissions to the atmosphere from the 
glycol dehydration unit reboiler vent and GCG separator (flash tank) 
vent (if present) are reduced by 95 percent through process 
modifications.
    (3) Control of HAP emissions from a GCG separator (flash tank) vent 
is not required if the owner or operator demonstrates, to the 
Administrator's satisfaction, that total HAP emissions to the 
atmosphere from the glycol dehydration unit reboiler vent and GCG 
separator (flash tank) vent are reduced by 95 percent.


Sec. 63.1276  [Reserved]


Sec. 63.1277  [Reserved]


Sec. 63.1278  [Reserved]


Sec. 63.1279  [Reserved]


Sec. 63.1280  [Reserved]


Sec. 63.1281  Control equipment requirements.

    (a) This section applies to each closed-vent system, and control 
device installed and operated by the owner or operator to control air 
emissions in accordance with the standards of this subpart.
    (b) [Reserved]
    (c) Closed-vent system requirements. (1) The closed-vent system 
shall route all gases, vapors, and fumes emitted from the material in 
the unit to a control device that meets the requirements specified in 
paragraph (d) of this section.
    (2) The closed-vent system shall be designed and operated with no 
detectable emissions.
    (3) If the closed-vent system contains one or more bypass devices 
that could be used to divert all or a portion of the gases, vapors, or 
fumes from entering the control device, the owner or operator shall 
meet the following requirements:
    (i) For each bypass device except as provided for in paragraph 
(c)(3)(ii) of this section, the owner or operator shall either:
    (A) Install, calibrate, maintain, and operate a flow indicator at 
the inlet to the bypass device that indicates at least once every 15 
minutes whether gas, vapor, or fume flow is present in the bypass 
device; or
    (B) Secure the valve installed at the inlet to the bypass device in 
the closed position using a car-seal or a lock-and-key type 
configuration. The owner or operator shall visually inspect the seal or 
closure mechanism at least once every month to verify that the valve is 
maintained in the closed position.
    (ii) Low leg drains, high point bleeds, analyzer vents, open-ended 
valves or lines, and safety devices are not subject to the requirements 
of paragraph (c)(3)(i) of this section.
    (d) Control device requirements. (1) The control device shall be 
one of the following devices:

[[Page 6329]]

    (i) An enclosed combustion device (e.g., thermal vapor incinerator, 
catalytic vapor incinerator, boiler, or process heater) that is 
designed and operated in accordance with one of the following 
performance requirements:
    (A) Reduces the mass content of either TOC or total HAP in the 
gases vented to the device by 95 percent by weight or greater, as 
determined in accordance with the requirements of Sec. 63.1282(d);
    (B) Reduces the concentration of either TOC or a total HAP in the 
exhaust gases at the outlet to the device to a level equal to or less 
than 20 parts per million by volume on a dry basis corrected to 3 
percent oxygen as determined in accordance with the requirements of 
Sec. 63.1282(d)(4); or
    (C) Operates at a minimum residence time of 0.5 second at a minimum 
temperature of 760 deg.C. If a boiler or process heater is used as the 
control device, then the vent stream shall be introduced into the flame 
zone of the boiler or process heater.
    (ii) A vapor recovery device (e.g., condenser) that is designed and 
operated to reduce the mass content of either TOC or total HAP in the 
gases vented to the device by 95 percent by weight or greater as 
determined in accordance with the requirements of Sec. 63.1282(d).
    (iii) A flare that is designed and operated in accordance with the 
requirements of Sec. 63.11(b).
    (2) Each control device used to comply with this subpart shall be 
operated at all times when material is placed in a unit vented to the 
control device except when maintenance or repair of a unit cannot be 
completed without a shutdown of the control device. An owner or 
operator may vent more than one unit to a control device used to comply 
with this subpart.
    (3) The owner or operator shall demonstrate that a control device 
achieves the performance requirements of paragraph (d)(1) of this 
section as follows:
    (i) An owner or operator shall demonstrate, using either a 
performance test as specified in paragraph (d)(3)(iii) of this section 
or a design analysis as specified in paragraph (d)(3)(iv) of this 
section, the performance of each control device except for the 
following:
    (A) A flare;
    (B) A boiler or process heater with a design heat input capacity of 
44 megawatts or greater;
    (C) A boiler or process heater into which the vent stream is 
introduced with the primary fuel; or
    (D) A boiler or process heater burning hazardous waste for which 
the owner or operator either has been issued a final permit under 40 
CFR part 270 and complies with the requirements of 40 CFR part 266, 
subpart H; or has certified compliance with the interim status 
requirements of 40 CFR part 266, subpart H.
    (ii) An owner or operator shall demonstrate the performance of each 
flare in accordance with the requirements specified in Sec. 63.11(b).
    (iii) For a performance test conducted to meet the requirements of 
paragraph (d)(3)(i) of this section, the owner or operator shall use 
the test methods and procedures specified in Sec. 63.1282(d) or (e).
    (iv) For a design analysis conducted to meet the requirements of 
paragraph (d)(3)(i) of this section, the design analysis shall meet the 
following requirements:
    (A) The design analysis shall include analysis of the vent stream 
characteristics and control device operating parameters for the 
applicable control device type as follows:
    (1) For a thermal vapor incinerator, the design analysis shall 
address the vent stream composition, constituent concentrations, and 
flow rate and shall establish the design minimum and average 
temperatures in the combustion zone and the combustion zone residence 
time.
    (2) For a catalytic vapor incinerator, the design analysis shall 
address the vent stream composition, constituent concentrations, flow 
rate, and shall establish the design minimum and average temperatures 
across the catalyst bed inlet and outlet, and the design service life 
of the catalyst.
    (3) For a boiler or process heater, the design analysis shall 
address the vent stream composition, constituent concentrations, and 
flow rate; shall establish the design minimum and average flame zone 
temperatures and combustion zone residence time; and shall describe the 
method and location where the vent stream is introduced into the flame 
zone.
    (4) For a condenser, the design analysis shall address the vent 
stream composition, constituent concentrations, flow rate, relative 
humidity, and temperature and shall establish the design outlet organic 
compound concentration level, design average temperature of the 
condenser exhaust vent stream, and the design average temperatures of 
the coolant fluid at the condenser inlet and outlet.
    (5) For a carbon adsorption system that regenerates the carbon bed 
directly on-site in the control device such as a fixed-bed adsorber, 
the design analysis shall address the vent stream composition, 
constituent concentrations, flow rate, relative humidity, and 
temperature and shall establish the design exhaust vent stream organic 
compound concentration level, adsorption cycle time, number and 
capacity of carbon beds, type and working capacity of activated carbon 
used for carbon beds, design total regeneration stream flow over the 
period of each complete carbon bed regeneration cycle, design carbon 
bed temperature after regeneration, design carbon bed regeneration 
time, and design service life of the carbon.
    (6) For a carbon adsorption system that does not regenerate the 
carbon bed directly on-site in the control device such as a carbon 
canister, the design analysis shall address the vent stream 
composition, constituent concentrations, flow rate, relative humidity, 
and temperature and shall establish the design exhaust vent stream 
organic compound concentration level, capacity of carbon bed, type and 
working capacity of activated carbon used for carbon bed, and design 
carbon replacement interval based on the total carbon working capacity 
of the control device and source operating schedule.
    (B) If the owner or operator and the Administrator do not agree on 
a demonstration of control device performance using a design analysis 
then the disagreement shall be resolved using the results of a 
performance test performed by the owner or operator in accordance with 
the requirements of paragraph (d)(3)(iii) of this section. The 
Administrator may choose to have an authorized representative observe 
the performance test.
    (4) The owner or operator shall operate each control device in 
accordance with the following requirements:
    (i) The control device shall be operating at all times when gases, 
vapors, and fumes are vented from the unit or units through the closed-
vent system to the control device.
    (ii) For each control device monitored in accordance with the 
requirements of Sec. 63.1283(d), the owner or operator shall operate 
the control device such that the actual value of each operating 
parameter required to be monitored in accordance with the requirements 
of Sec. 63.1283(d)(3) is greater than the minimum operating parameter 
value or less than the maximum operating parameter value, as 
appropriate, established for the control device in accordance with the 
requirements of Sec. 63.1283(d)(4).
    (iii) Failure by the owner or operator to operate the control 
device in accordance with the requirements of paragraph (d)(4)(ii) of 
this section shall

[[Page 6330]]

constitute a violation of the applicable emission standard of this 
subpart.
    (5) For each carbon adsorption system used as a control device to 
meet the requirements of paragraph (d)(1) of this section, the owner or 
operator shall manage the carbon as follows:
    (i) Following the initial startup of the control device, all carbon 
in the control device shall be replaced with fresh carbon on a regular, 
predetermined time interval that is no longer than the carbon service 
life established for the carbon adsorption system.
    (ii) All carbon removed from the control device shall be managed in 
one of the following manners:
    (A) Regenerated or reactivated in a thermal treatment unit for 
which the owner or operator has either been issued a final permit under 
40 CFR part 270, and designs and operates the unit in accordance with 
the requirements of 40 CFR part 264, subpart X; or certified compliance 
with the interim status requirements of 40 CFR part 265, subpart P.
    (B) Burned in a hazardous waste incinerator for which the owner or 
operator has been issued a final permit under 40 CFR part 270, and 
designs and operates the unit in accordance with the requirements of 40 
CFR part 264, subpart O.
    (C) Burned in a boiler or industrial furnace for which the owner or 
operator has either been issued a final permit under 40 CFR part 270, 
and designs and operates the unit in accordance with the requirements 
of 40 CFR part 266, subpart H, or has certified compliance with the 
interim status requirements of 40 CFR part 266, subpart H.


Sec. 63.1282  Test methods and compliance procedures.

    (a) Determination of glycol dehydration unit flow rate or benzene 
emissions. The procedures of this paragraph shall be used by an owner 
or operator to determine flow rate or benzene emissions to meet the 
criteria for an exemption from control requirements under 
Sec. 63.1274(b).
    (1) The determination of actual flow rate of natural gas to a 
glycol dehydration unit shall be made using the procedures of either 
paragraph (a)(1)(i) or (a)(1)(ii) of this section.
    (i) The owner or operator shall install and operate a monitoring 
instrument that directly measures flow to the glycol dehydration unit 
with an accuracy of plus or minus 2 percent.
    (ii) The owner or operator shall document that the actual annual 
average flow rate of the dehydration unit is less than 85 thousand 
cubic meters per day (3.0 million standard cubic feet per day).
    (2) The determination of benzene emissions from a glycol 
dehydration unit shall be made using the procedures of either paragraph 
(a)(2)(i) or (a)(2)(ii) of this section.
    (i) The owner or operator shall determine annual benzene emissions 
using the model GRI-GLYCalcTM, Version 3.0 or higher. Inputs 
to the model shall be representative of actual operating conditions of 
the glycol dehydration unit.
    (ii) The owner or operator shall determine an average mass rate of 
benzene emissions in kilograms per hour through direct measurement by 
performing three runs of Method 18 in 40 CFR part 60, appendix A (or an 
equivalent method), and averaging the results of the three runs. Annual 
emissions in kilograms per year shall be determined by multiplying the 
mass rate by the number of hours the unit is operated per year. This 
result shall be multiplied by 1.1023 E-03 to convert to tons 
per year.
    (b) No detectable emissions test procedure.
    (1) The procedure shall be conducted in accordance with Method 21, 
40 CFR part 60, appendix A.
    (2) The detection instrument shall meet the performance criteria of 
Method 21, 40 CFR part 60, appendix A, except the instrument response 
factor criteria in section 3.1.2(a) of Method 21 shall be for the 
average composition of the fluid, and not for each individual organic 
compound in the stream.
    (3) The detection instrument shall be calibrated before use on each 
day of its use by the procedures specified in Method 21, 40 CFR part 
60, appendix A.
    (4) Calibration gases shall be as follows:
    (i) Zero air (less than 10 parts per million by volume hydrocarbon 
in air); and
    (ii) A mixture of methane in air at a methane concentration of less 
than 10,000 parts per million by volume.
    (5) The background level shall be determined according to the 
procedures in Method 21, 40 CFR part 60, appendix A.
    (6) The arithmetic difference between the maximum organic 
concentration indicated by the instrument and the background level 
shall be compared with the value of 500 parts per million by volume. If 
the difference is less than 500 parts per million by volume, then no 
HAP emissions are detected.
    (c) [Reserved]
    (d) Control device performance test procedures. This paragraph 
applies to the performance testing of control devices. Owners or 
operators may elect to use the alternative procedures in paragraph (e) 
of this section for performance testing of a condenser used to control 
emissions from a glycol dehydration unit process vent.
    (1) Method 1 or 1A of 40 CFR part 60, appendix A, as appropriate, 
shall be used for selection of the sampling sites at the inlet and 
outlet of the control device.
    (i) To determine compliance with the control device percentage of 
reduction requirement specified in Sec. 63.1281(d)(1)(i)(A) or 
Sec. 63.1281(d)(1)(ii)(A), sampling sites shall be located at the inlet 
of the control device as specified in paragraphs (d)(1)(i)(A) and 
(d)(1)(i)(B) of this section, and at the outlet of the control device.
    (A) The control device inlet sampling site shall be located after 
the final product recovery device.
    (B) If a vent stream is introduced with the combustion air, or as a 
secondary fuel, into a boiler or process heater with a design capacity 
less than 44 megawatts, selection of the location of the inlet sampling 
sites shall ensure the measurement of total HAP or TOC concentration, 
as applicable, in all vent streams and primary and secondary fuels.
    (ii) To determine compliance with the enclosed combustion device 
total HAP concentration limit specified in Sec. 63.1281(d)(1)(i)(B), 
the sampling site shall be located at the outlet of the device.
    (2) The gas volumetric flow rate shall be determined using Method 
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
    (3) To determine compliance with the control device percentage of 
reduction requirement specified in Sec. 63.1281(d)(1)(i)(A) or 
Sec. 63.1281(d)(1)(ii)(A), the owner or operator shall use Method 18 of 
40 CFR part 60, appendix A of this chapter; alternatively, any other 
method or data that has been validated according to the applicable 
procedures in Method 301 of appendix A of this part may be used. The 
following procedures shall be used to calculate the percentage of 
reduction:
    (i) The minimum sampling time for each run shall be 1 hour in which 
either an integrated sample or a minimum of four grab samples shall be 
taken. If grab sampling is used, then the samples shall be taken at 
approximately equal intervals in time, such as 15 minute intervals 
during the run.
    (ii) The mass rate of either TOC (minus methane and ethane) or 
total HAP (Ei, Eo) shall be computed.

[[Page 6331]]

    (A) The following equations shall be used:
    [GRAPHIC] [TIFF OMITTED] TP06FE98.013
    
    [GRAPHIC] [TIFF OMITTED] TP06FE98.014
    
Where:
Cij, Coj=Concentration of sample component j of 
the gas stream at the inlet and outlet of the control device, 
respectively, dry basis, parts per million by volume.
Ei, Eo=Mass rate of TOC (minus methane and 
ethane) or total HAP at the inlet and outlet of the control device, 
respectively, dry basis, kilogram per hour.
Mij, Moj=Molecular weight of sample component j 
of the gas stream at the inlet and outlet of the control device, 
respectively, gram/gram-mole.
Qi, Qo=Flow rate of gas stream at the inlet and 
outlet of the control device, respectively, dry standard cubic meter 
per minute.
K2=Constant, 2.494 x 10-6 (parts per million)-1 (gram-mole 
per standard cubic meter) (kilogram/gram) (minute/hour), where standard 
temperature is 20 deg.C.

    (B) When the TOC mass rate is calculated, all organic compounds 
(minus methane and ethane) measured by Method 18, of 40 CFR part 60, 
appendix A shall be summed using the equation in paragraph 
(d)(3)(ii)(A) of this section.
    (C) When the total HAP mass rate is calculated, only HAP chemicals 
listed in Table 1 of this subpart shall be summed using the equation in 
paragraph (d)(3)(ii)(A) of this section.
    (iii) The percentage of reduction in TOC (minus methane and ethane) 
or total HAP shall be calculated as follows
[GRAPHIC] [TIFF OMITTED] TP06FE98.015

Where:

Rcd=Control efficiency of control device, percent.
Ei=Mass rate of TOC (minus methane and ethane) or total HAP 
at the inlet to the control device as calculated under paragraph 
(d)(3)(ii) of this section, kilograms TOC per hour or kilograms HAP per 
hour.

    Eo=Mass rate of TOC (minus methane and ethane) or total 
HAP at the outlet of the control device, as calculated under paragraph 
(d)(3)(ii) of this section, kilograms TOC per hour or kilograms HAP per 
hour.
    (iv) If the vent stream entering a boiler or process heater with a 
design capacity less than 44 megawatts is introduced with the 
combustion air or as a secondary fuel, the weight-percentage of 
reduction of total HAP or TOC (minus methane and ethane) across the 
device shall be determined by comparing the TOC (minus methane and 
ethane) or total HAP in all combusted vent streams and primary and 
secondary fuels with the TOC (minus methane and ethane) or total HAP 
exiting the device, respectively.
    (4) To determine compliance with the enclosed combustion device 
total HAP concentration limit specified in Sec. 63.1281(d)(1)(i)(B), 
the owner or operator shall use Method 18, 40 CFR part 60, appendix A 
to measure either TOC (minus methane and ethane) or total HAP. 
Alternatively, any other method or data that has been validated 
according to Method 301, appendix A of this part, may be used. The 
following procedures shall be used to calculate parts per million by 
volume concentration, corrected to 3 percent oxygen:
    (i) The minimum sampling time for each run shall be 1 hour in which 
either an integrated sample or a minimum of four grab samples shall be 
taken. If grab sampling is used, then the samples shall be taken at 
approximately equal intervals in time, such as 15-minute intervals 
during the run.
    (ii) The TOC concentration or total HAP concentration shall be 
calculated according to paragraph (d)(4)(ii)(A) or (d)(4)(ii)(B) of 
this section.
    (A) The TOC concentration (CTOC) is the sum of the 
concentrations of the individual components and shall be computed for 
each run using the following equation:
[GRAPHIC] [TIFF OMITTED] TP06FE98.016

Where:

CTOC=Concentration of total organic compounds minus methane 
and ethane, dry basis, parts per million by volume.
Cji=Concentration of sample components j of sample i, dry 
basis, parts per million by volume.
n=Number of components in the sample.
x=Number of samples in the sample run.

    (B) The total HAP concentration (CHAP) shall be computed 
according to the equation in paragraph (d)(4)(ii)(A) of this section, 
except that only HAP chemicals listed in Table 1 of this subpart shall 
be summed.
    (iii) The TOC concentration or total HAP concentration shall be 
corrected to 3 percent oxygen as follows:
    (A) The emission rate correction factor or excess air, integrated 
sampling and analysis procedures of Method 3B, 40 CFR part 60, appendix 
A shall be used to determine the oxygen concentration 
(%O2d). The samples shall be taken during the same time that 
the samples are taken for determining TOC concentration or total HAP 
concentration.
    (B) The concentration corrected to 3 percent oxygen (Cc) 
shall be computed using the following equation:
[GRAPHIC] [TIFF OMITTED] TP06FE98.017

Where:

Cc=TOC concentration of total HAP concentration corrected to 
3 percent oxygen, dry basis, parts per million by volume.
Cm=TOC concentration or total HAP concentration, dry basis, 
parts per million by volume.
%O2d=Concentration of oxygen, dry basis, percent by volume.

    (e) As an alternative to the procedures in paragraph (d) of this 
section, an owner or operator may elect to use the procedures 
documented in the Gas Research Institute Report entitled, ``Atmospheric 
Rich/Lean Method for Determining Glycol Dehydrator Emissions,'' (GRI-
95/0368.1).


Sec. 63.1283  Inspection and monitoring requirements.

    (a) This section applies to an owner or operator using air emission 
controls in accordance with the requirements of Sec. 63.1275.
    (b) [Reserved]
    (c) Closed-vent system inspection and monitoring requirements. (1) 
The owner or operator shall visually inspect and monitor for no 
detectable emissions each closed-vent system at the following times:
    (i) On or before the date that the unit connected to the closed-
vent system becomes subject to the provisions of this subpart;
    (ii) At least once per year after the date that the closed-vent 
system is inspected in accordance with the requirements of paragraph 
(c)(1)(i) of this section; and
    (iii) At other times as requested by the Administrator.
    (2) To visually inspect a closed-vent system, the owner or operator 
shall view

[[Page 6332]]

the entire length of ductwork, piping and connections to covers and 
control devices for evidence of visible defects (such as holes in 
ductwork or piping and loose connections) that may affect the ability 
of the system to operate with no detectable emissions. A visible hole, 
gap, tear, or split in the closed-vent system is defined as a leak 
which shall be repaired in accordance with paragraph (c)(4) of this 
section.
    (3) To monitor a closed-vent system for no detectable emissions, 
the owner or operator shall use Method 21, 40 CFR part 60, appendix A 
to test each closed-vent system joint, seam, or other connection. For 
the annual leak detection monitoring after the initial leak detection 
monitoring, the owner or operator is not required to monitor those 
closed-vent system components which continuously operate at a pressure 
below atmospheric pressure or those closed-vent system joints, seams, 
or other connections that are permanently or semi-permanently sealed 
(e.g., a welded joint between two sections of metal pipe or a bolted 
and gasketed pipe flange).
    (4) When a leak is detected by either of the methods specified in 
paragraph (c)(2) or (c)(3) of this section, the owner or operator shall 
make a first attempt at repairing the leak no later than 5 calendar 
days after the leak is detected. Repair of the leak shall be completed 
as soon as practicable, but no later than 15 calendar days after the 
leak is detected.
    (d) Control device monitoring requirements. (1) For each control 
device except as provided for in paragraph (d)(2) of this section, the 
owner or operator shall install and operate a continuous monitoring 
system in accordance with the requirements of paragraphs (d)(3) through 
(d)(5) of this section that will allow a determination be made whether 
the control device is continuously achieving the applicable performance 
requirements of Sec. 63.1281.
    (2) An owner or operator is exempted from the monitoring 
requirements specified in paragraphs (d)(3) through (d)(5) of this 
section for the following types of control devices:
    (i) A boiler or process heater in which all vent streams are 
introduced with primary fuel; or
    (ii) A boiler or process heater with a design heat input capacity 
equal to or greater than 44 megawatts.
    (3) The owner or operator shall install, calibrate, operate, and 
maintain a device equipped with a continuous recorder to measure the 
values of operating parameters appropriate for the control device as 
specified in either paragraph (d)(3)(i), (d)(3)(ii), or (d)(3)(iii) of 
this section. The monitoring equipment shall be installed, calibrated, 
and maintained in accordance with the equipment manufacturer's 
specifications or other written procedures that provide adequate 
assurance that the equipment would reasonably be expected to monitor 
accurately. The continuous recorder shall be a data recording device 
that either records an instantaneous data value at least once every 15 
minutes or records 15-minute or more frequent block average values. The 
owner or operator shall use any of the following continuous monitoring 
systems:
    (i) A continuous monitoring system that measures the following 
operating parameters as applicable:
    (A) For a thermal vapor incinerator, a temperature monitoring 
device equipped with a continuous recorder. The monitoring device shall 
have an accuracy of 1 percent of the temperature being 
monitored in  deg.C, or 0.5  deg.C, whichever value is 
greater. The temperature sensor shall be installed at a location in the 
combustion chamber downstream of the combustion zone.
    (B) For a catalytic vapor incinerator, a temperature monitoring 
device equipped with a continuous recorder. The device shall be capable 
of monitoring temperature at two locations and have an accuracy of 
1 percent of the temperature being monitored in  deg.C, or 
0.5  deg.C, whichever value is greater. One temperature 
sensor shall be installed in the vent stream at the nearest feasible 
point to the catalyst bed inlet and a second temperature sensor shall 
be installed in the vent stream at the nearest feasible point to the 
catalyst bed outlet.
    (C) For a flare, a heat sensing monitoring device equipped with a 
continuous recorder that indicates the continuous ignition of the pilot 
flame.
    (D) For a boiler or process heater with a design heat input 
capacity of less than 44 megawatts, a temperature monitoring device 
equipped with a continuous recorder. The temperature monitoring device 
shall have an accuracy of 1 percent of the temperature 
being monitored in  deg.C, or 0.5  deg.C, whichever value 
is greater. The temperature sensor shall be installed at a location in 
the combustion chamber downstream of the combustion zone.
    (E) For a condenser, a temperature monitoring device equipped with 
a continuous recorder. The temperature monitoring device shall have an 
accuracy of 1 percent of the temperature being monitored in 
 deg.C, or 0.5  deg.C, whichever value is greater. The 
temperature sensor shall be installed at a location in the exhaust vent 
stream from the condenser.
    (F) For a regenerative-type carbon adsorption system, an 
integrating regeneration stream flow monitoring device equipped with a 
continuous recorder, and a carbon bed temperature monitoring device 
equipped with a continuous recorder. The integrating regeneration 
stream flow monitoring device shall have an accuracy of 10 
percent and measure the total regeneration stream mass flow during the 
carbon bed regeneration cycle. The temperature monitoring device shall 
have an accuracy of 1 percent of the temperature being 
monitored in  deg.C, or 0.5 deg.C, whichever value is 
greater and measure the carbon bed temperature both after regeneration 
and within 15 minutes of completing the cooling cycle, and over the 
duration of the carbon bed steaming cycle.
    (ii) A continuous monitoring system that measures the concentration 
level of organic compounds in the exhaust vent stream from the control 
device using an organic monitoring device equipped with a continuous 
recorder.
    (iii) A continuous monitoring system that measures alternative 
operating parameters other than those specified in paragraph (d)(3)(i) 
or (d)(3)(ii) of this section upon approval of the Administrator as 
specified in Sec. 63.8 (f)(1) through (f)(5).
    (4) For each operating parameter monitored in accordance with the 
requirements of paragraph (d)(3) of this section, the owner or operator 
shall establish a minimum operating parameter value or a maximum 
operating parameter value, as appropriate for the control device, to 
define the conditions at which the control device must be operated to 
continuously achieve the applicable performance requirements of 
Sec. 63.1281. Each minimum or maximum operating parameter value shall 
be established as follows:
    (i) If the owner or operator conducts performance tests in 
accordance with the requirements of Sec. 63.1281 to demonstrate that 
the control device achieves the applicable performance requirements 
specified in Sec. 63.1281, then the minimum operating parameter value 
or the maximum operating parameter value shall be established based on 
values measured during the performance test and supplemented, as 
necessary, by control device design analysis and manufacturer 
recommendations.
    (ii) If the owner or operator uses control device design analysis 
in accordance with the requirements of Sec. 63.1281(d)(3)(iv) to 
demonstrate that the control device achieves the applicable performance 
requirements

[[Page 6333]]

specified in Sec. 63.1281(d)(1), then the minimum operating parameter 
value or the maximum operating parameter value shall be established 
based on the control device design analysis and the control device 
manufacturer's recommendations.
    (5) The owner or operator shall regularly inspect the data recorded 
by the continuous monitoring system to determine whether the control 
device is operating in accordance with the applicable requirements of 
Sec. 63.1281(d).


Sec. 63.1284  Recordkeeping requirements.

    (a) The recordkeeping provisions of subpart A of this part that 
apply and those that do not apply to owners and operators of facilities 
subject to this subpart are listed in Table 2 of this subpart.
    (b) Except as specified in paragraphs (c) and (d) of this section, 
each owner or operator of a facility subject to this subpart shall 
maintain the following records in accordance with the requirements of 
Sec. 63.10(b)(1):
    (1) Records specified in Sec. 63.10(b)(2);
    (2) Records specified in Sec. 63.10(c) for each continuous 
monitoring system operated by the owner or operator in accordance with 
the requirements of Sec. 63.1283(d).
    (c) [Reserved]
    (d) An owner or operator that is exempt from control requirements 
under Sec. 63.1274(b) shall maintain a record of the design capacity 
(in terms of natural gas flow rate to the unit per day) of each glycol 
dehydration unit that is not controlled according to the requirements 
of Sec. 63.1274(a).


Sec. 63.1285  Reporting requirements.

    (a) The reporting provisions of subpart A of this part that apply 
and those that do not apply to owners and operators of facilities 
subject to this subpart are listed in Table 2 of this subpart.
    (b) Each owner or operator of a facility subject to this subpart 
shall submit the following reports to the Administrator:
    (1) An Initial Notification as described in Sec. 63.9 (a) through 
(d), except that the notification required by Sec. 63.9(b)(2) shall be 
submitted not later than one year after the effective date of this 
standard.
    (2) A Notification of Performance Tests as specified in 
Sec. 63.7(b), Sec. 63.9(e), and Sec. 63.9(g).
    (3) A Notification of Compliance Status as specified in 
Sec. 63.9(h).
    (4) Performance test reports as specified in Sec. 63.10(d)(2) and 
performance evaluation reports specified in Sec. 63.10(e)(2). Separate 
performance evaluation reports as described in Sec. 63.10(e)(2) are not 
required if the information is included in the summary report specified 
in paragraph (b)(6) of this section.
    (5) Startup, shutdown, and malfunction reports, as specified in 
Sec. 63.10(d)(5), shall be submitted as required. Separate startup, 
shutdown, or malfunction reports as described in Sec. 63.10(d)(5)(i) 
are not required if the information is included in the report specified 
in paragraph (b)(6) of this section.
    (6) The excess emission and CMS performance report and summary 
report as specified in Sec. 63.10(e)(3) shall be submitted on a semi-
annual basis (i.e., once every 6-month period). The summary report 
shall be entitled ``Summary Report--Gaseous Excess Emissions and 
Continuous Monitoring System Performance.''
    (7) The owner or operator shall meet the requirements specified in 
paragraph (b) of this section for any emission point or material that 
becomes subject to the standards in this subpart due to an increase in 
flow, concentration, or other parameters equal to or greater than the 
limits specified in this subpart.
    (8) For each control device other than a flare used to meet the 
requirements of this subpart, the owner or operator shall submit the 
following information for each operating parameter required to be 
monitored in accordance with the requirements of Sec. 63.1283(d):
    (i) The minimum operating parameter value or maximum operating 
parameter value, as appropriate for the control device, established by 
the owner or operator to define the conditions at which the control 
device must be operated to continuously achieve the applicable 
performance requirements of Sec. 63.1281(d)(1).
    (ii) An explanation of the rationale for why the owner or operator 
selected each of the operating parameter values established in 
Sec. 63.1281(d). This explanation shall include any data and 
calculations used to develop the value and a description of why this 
value indicates that the control device is operating in accordance with 
the applicable requirements of Sec. 63.1281(d)(1).
    (9) Each owner or operator of a major source subject to this 
subpart that is not subject to the control requirements for glycol 
dehydration unit process vents in Sec. 63.765 is exempt from all 
reporting requirements for major sources in this subpart.
    (c) Each owner or operator of a facility subject to this subpart 
that is an area source is exempt from all reporting requirements in 
this subpart.


Sec. 63.1286  Delegation of authority. [Reserved]


Sec. 63.1287  Alternative means of emission limitation.

    (a) If, in the judgment of the Administrator, an alternative means 
of emission limitation will achieve a reduction in HAP emissions at 
least equivalent to the reduction in HAP emissions from that source 
achieved under the applicable requirements in Secs. 63.1274 through 
63.1281, the Administrator will publish a notice in the Federal 
Register permitting the use of the alternative means for purposes of 
compliance with that requirement. The notice may condition the 
permission on requirements related to the operation and maintenance of 
the alternative means.
    (b) Any notice under paragraph (a) of this section shall be 
published only after public notice and an opportunity for a hearing.
    (c) Any person seeking permission to use an alternative means of 
compliance under this section shall collect, verify, and submit to the 
Administrator information showing that this means achieves equivalent 
emission reductions.


Sec. 63.1288  [Reserved]


Sec. 63.1289  [Reserved]

     Table 1 to Subpart HHH--List of Hazardous Air Pollutants (HAP)     
------------------------------------------------------------------------
              CAS No.a                          Chemical name           
------------------------------------------------------------------------
75070..............................  Acetaldehyde.                      
71432..............................  Benzene (includes benzene in       
                                      gasoline).                        
75150..............................  Carbon disulfide.                  
463581.............................  Carbonyl sulfide.                  
100414.............................  Ethyl benzene.                     
107211.............................  Ethylene glyco.                    
50000..............................  Formaldehyde.                      
110543.............................  n-Hexane.                          
91203..............................  Naphthalene.                       
108883.............................  Toluene.                           
540841.............................  2,2,4-Trimethylpentane.            
1330207............................  Xylenes (isomers and mixture).     
95476..............................  o-Xylene.                          
108383.............................  m-Xylene.                          
106423.............................  p-Xylenea.                         
------------------------------------------------------------------------
a CAS numbers refer to the Chemical Abstracts Services registry number  
  assigned to specific compounds, isomers, or mixtures of compounds.    


[[Page 6334]]


                   Table 2 of Subpart HHH.--Applicability of 40 CFR Part 63 General Provisions                  
----------------------------------------------------------------------------------------------------------------
     General provisions  reference         Applicable to subpart HHH                     Comment                
----------------------------------------------------------------------------------------------------------------
Sec.  63.1(a)(1)......................  Yes...........................                                          
Sec.  63.1(a)(2)......................  Yes...........................                                          
Sec.  63.1(a)(3)......................  Yes...........................                                          
Sec.  63.1(a)(4)......................  Yes...........................                                          
Sec.  63.1(a)(5)......................  No............................  Section reserved.                       
Sec.  63.1(a)(6)-(a)(8)...............  Yes...........................                                          
Sec.  63.1(a)(9)......................  No............................  Section reserved.                       
Sec.  63.1(a)(10).....................  Yes...........................                                          
Sec.  63.1(a)(11).....................  Yes...........................                                          
Sec.  63.1(a)(12)-(a)(14).............  Yes...........................                                          
Sec.  63.1(b)(1)......................  No............................  Subpart HHH specifies applicability.    
Sec.  63.1(b)(2)......................  Yes...........................                                          
Sec.  63.1(b)(3)......................  No............................                                          
Sec.  63.1(c)(1)......................  No............................  Subpart HHH specifies applicability.    
Sec.  63.1(c)(2)......................  No............................                                          
Sec.  63.1(c)(3)......................  No............................  Section reserved.                       
Sec.  63.1(c)(4)......................  Yes...........................                                          
Sec.  63.1(c)(5)......................  Yes...........................                                          
Sec.  63.1(d).........................  No............................  Section reserved.                       
Sec.  63.1(e).........................  Yes...........................                                          
Sec.  63.2............................  Yes...........................  Except definition of ``major source'' is
                                                                         unique for this source category and    
                                                                         there are additional definitions       
                                                                         included in subpart HHH.               
Sec.  63.3(a)-(c).....................  Yes...........................                                          
Sec.  63.4(a)(1)-(a)(3)...............  Yes...........................                                          
Sec.  63.4(a)(4)......................  No............................  Section reserved.                       
Sec.  63.4(a)(5)......................  Yes...........................                                          
Sec.  63.4(b).........................  Yes...........................                                          
Sec.  63.49(c)........................  Yes...........................                                          
Sec.  63.5(a)(1)......................  Yes...........................                                          
Sec.  63.5(a)(2)......................  No............................  Preconstruction review required only for
                                                                         major sources that commence            
                                                                         construction after promulgation of the 
                                                                         standard.                              
Sec.  63.5(b)(1)......................  Yes...........................                                          
Sec.  63.5(b)(2)......................  No............................  Section reserved.                       
Sec.  63.5(b)(3)......................  Yes...........................                                          
Sec.  63.5(b)(4)......................  Yes...........................                                          
Sec.  63.5(b)(5)......................  Yes...........................                                          
Sec.  63.5(b)(6)......................  Yes...........................                                          
Sec.  63.5(c).........................  No............................  Section reserved.                       
Sec.  63.5(d)(1)......................  Yes...........................                                          
Sec.  63.5(d)(2)......................  Yes...........................                                          
Sec.  63.5(d)(3)......................  Yes...........................                                          
Sec.  63.5(d)(4)......................  Yes...........................                                          
Sec.  63.5(e).........................  Yes...........................                                          
Sec.  63.5(f)(1)......................  Yes...........................                                          
Sec.  63.5(f)(2)......................  Yes...........................                                          
Sec.  63.6(a).........................  Yes...........................                                          
Sec.  63.6(b)(1)......................  Yes...........................                                          
Sec.  63.6(b)(2)......................  Yes...........................                                          
Sec.  63.6(b)(3)......................  Yes...........................                                          
Sec.  63.6(b)(4)......................  Yes...........................                                          
Sec.  63.6(b)(5)......................  Yes...........................                                          
Sec.  63.6(b)(6)......................  No............................  Section reserved.                       
Sec.  63.6(b)(7)......................  Yes...........................                                          
Sec.  63.6(c)(1)......................  Yes...........................                                          
Sec.  63.6(c)(2)......................  Yes...........................                                          
Sec.  63.6(c)(3)-(c)(4)...............  No............................  Sections reserved.                      
Sec.  63.6(c)(5)......................  Yes...........................                                          
Sec.  63.6(d).........................  No............................  Section reserved.                       
Sec.  63.6(e).........................  Yes...........................                                          
Sec.  63.6(f)(1)......................  Yes...........................                                          
Sec.  63.6(f)(2)......................  Yes...........................                                          
Sec.  63.6(f)(3)......................  Yes...........................                                          
Sec.  63.6(g).........................  Yes...........................                                          
Sec.  63.6(h).........................  No............................  Subpart HHH does not require the use of 
                                                                         a continuous emissions monitoring      
                                                                         system.                                
Sec.  63.6(i)(1)-(i)(14)..............  Yes...........................                                          
Sec.  63.6(i)(15).....................  No............................  Section reserved.                       
Sec.  63.6(i)(16).....................  Yes...........................                                          
Sec.  63.6(j).........................  Yes...........................                                          
Sec.  63.7(a)(1)......................  Yes...........................                                          
Sec.  63.7(a)(2)......................  Yes...........................                                          

[[Page 6335]]

                                                                                                                
Sec.  63.7(a)(3)......................  Yes...........................                                          
Sec.  63.7(b).........................  Yes...........................                                          
Sec.  63.7(c).........................  Yes...........................                                          
Sec.  63.7(d).........................  Yes...........................                                          
Sec.  63.7(e)(1)......................  Yes...........................                                          
Sec.  63.7(e)(2)......................  Yes...........................                                          
Sec.  63.7(e)(3)......................  Yes...........................                                          
Sec.  63.7(e)(4)......................  Yes...........................                                          
Sec.  63.7(f).........................  Yes...........................                                          
Sec.  63.7(g).........................  Yes...........................                                          
Sec.  63.7(h).........................  Yes...........................                                          
Sec.  63.8(a)(1)......................  Yes...........................                                          
Sec.  63.8(a)(2)......................  Yes...........................                                          
Sec.  63.8(a)(3)......................  No............................  Section reserved.                       
Sec.  63.8(a)(4)......................  Yes...........................                                          
Sec.  63.8(b)(1)......................  Yes...........................                                          
Sec.  63.8(b)(2)......................  Yes...........................                                          
Sec.  63.8(b)(3)......................  Yes...........................                                          
Sec.  63.8(c)(1)......................  Yes...........................                                          
Sec.  63.8(c)(2)......................  Yes...........................                                          
Sec.  63.8(c)(3)......................  Yes...........................                                          
Sec.  63.8(c)(4)......................  No............................                                          
Sec.  63.8(c)(5)-(c)(8)...............  Yes...........................                                          
Sec.  63.8(d).........................  Yes...........................                                          
Sec.  63.8(e).........................  Yes...........................                                          
Sec.  63.8(f)(1)-(f)(5)...............  Yes...........................                                          
Sec.  63.8(f)(6)......................  No............................  Subpart HHH does not require the use of 
                                                                         a continuous emissions monitor.        
Sec.  63.8(g).........................  No............................  Subpart HHH specifies continuous        
                                                                         monitoring system data reduction       
                                                                         requirements.                          
Sec.  63.9(a).........................  Yes...........................                                          
Sec.  63.9(b)(1)......................  Yes...........................                                          
Sec.  63.9(b)(2)......................  Yes...........................  Sources are given one year (rather than 
                                                                         120 days) to submit this notification. 
Sec.  63.9(b)(3)......................  Yes...........................                                          
Sec.  63.9(b)(4)......................  Yes...........................                                          
Sec.  63.9(b)(5)......................  Yes...........................                                          
Sec.  63.9(c).........................  Yes...........................                                          
Sec.  63.9(d).........................  Yes...........................                                          
Sec.  63.9(e).........................  Yes...........................                                          
Sec.  63.9(f).........................  No............................                                          
Sec.  63.9(g).........................  Yes...........................                                          
Sec.  63.9(h)(1)-(h)(3)...............  Yes...........................                                          
Sec.  63.9(h)(4)......................  No............................  Section reserved.                       
Sec.  63.9(h)(5)-(h)(6)...............  Yes...........................                                          
Sec.  63.9(i).........................  Yes...........................                                          
Sec.  63.9(j).........................  Yes...........................                                          
Sec.  63.10(a)........................  Yes...........................                                          
Sec.  63.10(b)(1).....................  Yes...........................                                          
Sec.  63.10(b)(2).....................  Yes...........................                                          
Sec.  63.10(b)(3).....................  No............................                                          
Sec.  63.10(c)(1).....................  Yes...........................                                          
Sec.  63.10(c)(2)-(c)(4)..............  No............................  Sections reserved.                      
Sec.  63.10(c)(5)-(c)(8)..............  Yes...........................                                          
Sec.  63.10(c)(9).....................  No............................  Section reserved.                       
Sec.  63.10(c)(10)-(c)(15)............  Yes...........................                                          
Sec.  63.10(d)(1).....................  Yes...........................                                          
Sec.  63.10(d)(2).....................  Yes...........................                                          
Sec.  63.10(d)(3).....................  Yes...........................                                          
Sec.  63.10(d)(4).....................  Yes...........................                                          
Sec.  63.10(d)(5).....................  Yes...........................  Subpart HHH requires major sources to   
                                                                         submit startup, shutdown and           
                                                                         malfunction report semi-annually.      
Sec.  63.10(e)........................  Yes...........................  Subpart HHH requires major sources to   
                                                                         submit continuous monitoring system    
                                                                         performance reports semi-annually.     
                                                                                                                

[[Page 6336]]

                                                                                                                
Sec.  63.10(f)........................  Yes...........................                                          
Sec.  63.11(a)-(b)....................  Yes...........................                                          
Sec.  63.12(a)-(c)....................  Yes...........................                                          
Sec.  63.13(a)-(c)....................  Yes...........................                                          
Sec.  63.14(a)-(b)....................  Yes...........................                                          
Sec.  63.15(a)-(b)....................  Yes...........................                                          
----------------------------------------------------------------------------------------------------------------

[FR Doc. 98-2714 Filed 2-5-98; 8:45 am]
BILLING CODE 6560-50-U