[Federal Register Volume 64, Number 116 (Thursday, June 17, 1999)]
[Rules and Regulations]
[Pages 32610-32664]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 99-12894]



[[Page 32609]]

_______________________________________________________________________

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; Final 
Rule

  Federal Register / Vol. 64, No. 116 / Thursday, June 17, 1999 / Rules 
and Regulations  

[[Page 32610]]



ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[AD-FRL-6346-8]
RIN 2060-AE34


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rules.

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

SUMMARY: These promulgated national emission standards for hazardous 
air pollutants (NESHAP) limit emissions of hazardous air pollutants 
(HAP) from oil and natural gas production and natural gas transmission 
and storage facilities. These final rules 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 69,000 megagrams per year (Mg/
yr) of HAP are emitted from facilities in these source categories. The 
primary HAP emitted by the facilities covered by these final standards 
include benzene, toluene, ethyl benzene, mixed xylenes (collectively 
referred to as BTEX), and n-hexane. Benzene is carcinogenic and has 
also been shown to cause various adverse health effects other than 
cancer (i.e., noncancer effects). The other four HAP are not classified 
as carcinogens based on available information; however, exposures to 
these four HAP have been shown to cause various noncancer effects.
    The EPA estimates that these promulgated NESHAP will reduce HAP 
emissions from major sources in the oil and natural gas production 
source category by 77 percent and from major sources in the natural gas 
transmission and storage source category by 95.0 percent.

EFFECTIVE DATE: This regulation is effective June 17, 1999. See 
SUPPLEMENTARY INFORMATION concerning judicial review.

ADDRESSES: Docket. A docket, No. A-94-04, containing information 
considered by the EPA in developing the promulgated 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 5:30 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. The promulgated 
regulations, background information document (BID) volumes 1 and 2, and 
other supporting information are available for inspection and copying. 
A reasonable fee may be charged for copying.
    Responses to Comments Document. The responses to comments document 
for the promulgated standards may be obtained from the EPA Library (MD-
35), Research Triangle Park, North Carolina 27711, telephone (919) 541-
2777, or from the National Technical Information Services, 5285 Port 
Royal Road, Springfield, Virginia 22151, telephone (703) 605-6000 or 
(800) 553-6847 or via the Internet at www.fedworld.gov/ntis/
ntishome.html. 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 Final Standards: Summary of Public Comments and 
Responses'' (EPA-453/R-99-004b, May 1999). The document contains the 
following: (1) a summary of all the public comments made on the 
proposed standards and the Administrator's responses to the comments 
and (2) a summary of the changes made to the standards since proposal. 
This document is also available for downloading from the Technology 
Transfer Network (see SUPPLEMENTARY INFORMATION).

FOR FURTHER INFORMATION CONTACT: For information concerning today's 
action, contact Mr. Greg Nizich, Waste and Chemical Processes Group 
(MD-13), U.S. Environmental Protection Agency, Research Triangle Park, 
North Carolina 27711; telephone: (919) 541-3078; facsimile: (919) 541-
0246; 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 these 
actions. This table lists the types of entities that the EPA is now 
aware could potentially be regulated by these actions. Other types of 
entities not listed in the table could also be regulated. To determine 
whether your facility is regulated by these actions, you should 
carefully examine the applicability criteria in sections 63.760 and 
63.1270 of the rules. If you have questions regarding the applicability 
of these actions to a particular entity, consult the person listed in 
the preceding FOR FURTHER INFORMATION CONTACT section.
    Technology Transfer Network. This document, the final regulatory 
texts, and BID volumes 1 and 2 are available in Docket No. A-94-04 from 
the EPA's Air and Radiation Docket and Information Center (see 
ADDRESSES). They can also be accessed through the EPA's Technology 
Transfer Network (TTN) Internet web site at: http://www.epa.gov/ttn/
oarpg.
    Judicial Review. National emission standards for hazardous air 
pollutants for facilities in the oil and natural gas production and 
natural gas transmission and storage source categories were proposed in 
the Federal Register on February 6, 1998 (63 FR 6288). This Federal 
Register action announces the EPA's final decisions on the rules. Under 
section 307(b)(1) of the Act, judicial review of the NESHAP is 
available only by filing a petition for review in the U.S. Court of 
Appeals for the District of Columbia Circuit within 60 days of today's 
publication of these final rules. Under section 307(b)(2) of the Act, 
the requirements that are the subject of today's action may not be 
challenged later in civil or criminal proceedings brought by the EPA to 
enforce these requirements.
    Preamble Outline. The following outline is provided to aid in 
reading the preamble to the promulgated oil and natural gas production 
and natural gas transmission and storage NESHAP.

I. Background
II. Summary of Considerations in Developing the Rules
    A. Purpose of the Regulations
    B. Technical Basis of the Regulations
    C. Stakeholder and Public Participation
III. Summary of Promulgated Standards
    A. Promulgated Standards for Oil and Natural Gas Production for 
Major Sources
    B. Promulgated Standards for Natural Gas Transmission and 
Storage for Major Sources
    C. Recordkeeping and Reporting Provisions
IV. Summary of Impacts
    A. HAP Emission Reductions
    B. Secondary Environmental Impacts
    C. Energy Impacts
    D. Cost Impacts

[[Page 32611]]

    E. Economic Impacts
V. Significant Comments and Changes to the Proposed Standards
    A. Definition of Facility
    B. Definition of ``Associated Equipment''
    C. Applicability
    D. Glycol Dehydration Unit Process Vent Standards
    E. Storage Vessel Standards
    F. Standards for Natural Gas Transmission and Storage
    G. Monitoring, Recordkeeping, and Reporting Requirements
    H. Cost and Economic Impacts
VI. Administrative Requirements
    A. Docket
    B. Paperwork Reduction Act
    C. Executive Order 12866: A Significant Regulatory Action 
Determination
    D. Regulatory Flexibility Act
    E. Congressional Review Act
    F. Unfunded Mandates Reform Act
    G. Executive Order 12875: Enhancing the Intergovernmental 
Partnership
    H. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    I. Executive Order 13084: Consultation and Coordination with 
Indian Tribal Governments
    J. National Technology Transfer and Advancement Act

    The following conversions from metric to English units are provided 
to aid in reading the preamble to the promulgated oil and natural gas 
production and natural gas transmission and storage NESHAP.

----------------------------------------------------------------------------------------------------------------
           Metric values                                      Equivalent English values
----------------------------------------------------------------------------------------------------------------
0.31 cubic meter per liter (m3/      1,750 standard cubic feet per barrel (ft 3/barrel).
 liter).
39,700 liter/day...................  250 barrels per day (bpd).
79,500 liter/day...................  500 bpd.
0.90 Megagrams per year (Mg/yr)....  1.0 ton per year (tpy).
18.4 thousand cubic meters per day   650 thousand cubic feet per day (scf/day).
 (m3/day).
28.3 thousand m3/day...............  1 million scf/day (MMscf/day).
85 thousand m3/day.................  3 MMscf/day.
283 thousand m3/day................  10 MMscf/day.
----------------------------------------------------------------------------------------------------------------

I. Background

    Section 112(b) of the Act lists 188 HAP and directs the EPA to 
develop rules to control all major and some area sources emitting HAP. 
On July 16, 1992 (57 FR 31576), the EPA published a list of major and 
area sources for which NESHAP are to be published (i.e., the source 
category list). Oil and natural gas production facilities were listed 
as a category of major sources.
    The EPA included natural gas transmission and storage facilities in 
the proposed initial listing of source categories that was published in 
1991. Comments received on the proposed initial list indicated that 
this source category did not contain major sources of HAP. As a result, 
natural gas transmission and storage facilities were not included as a 
distinct source category in the July 1992 final list of source 
categories of major sources of HAP.
    During the development of the standards for the oil and natural gas 
production source category, information was obtained on glycol 
dehydration unit HAP emissions that are representative of both oil and 
natural gas production facilities and natural gas transmission and 
storage facilities. The information indicated that natural gas 
transmission and storage facilities have the potential to be major HAP 
sources. In addition, representatives of the natural gas transmission 
and storage source category stated to the EPA that there are major 
source glycol dehydration units in the source category. Therefore, the 
EPA amended the source category list on February 12, 1998 (63 FR 7155) 
to add natural gas transmission and storage as a major source category.
    On February 6, 1998, the EPA also gave notice of its intention to 
add oil and natural gas production as an area source category (63 FR 
6291), but did not amend the source category list to include such a 
category. In order to ensure that regulations applicable to the area 
source category are consistent with the Urban Air Toxics Strategy, to 
be implemented under section 112(k) of the Act, the EPA has deferred 
the regulation of oil and natural gas production facilities which are 
area sources until the Urban Air Toxics Strategy is finalized. The EPA 
expects this strategy to be finalized later this year.

II. Summary of Considerations in Developing the Rules

A. Purpose of the Regulations

    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 67,000 Mg/yr of HAP are emitted from 
facilities in the oil and natural gas production source category and 
2,100 Mg/yr of HAP are emitted from facilities 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 likelihood of these adverse health effects 
depends on the range of ambient concentrations and the amount, 
frequency, and duration of exposures. The ambient concentrations are 
influenced by source-specific characteristics such as emission rates 
and local meteorological conditions. Exposure and health impacts due to 
the ambient concentrations are dependent on multiple factors that 
affect human variability such as genetics, age, health status (e.g., 
the presence of pre-existing disease), lifestyle, location of 
residence, activity patterns, and other factors.
    Benzene, one of the HAP associated with these NESHAP, is classified 
as a known human carcinogen based on convincing human evidence (such as 
observed increases in the incidence of leukemia in exposed workers), as 
well as supporting evidence from animal studies. 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

[[Page 32612]]

irregular heartbeat. Repeated exposure to high concentrations may cause 
additional nervous system effects, including incoordination, tremors, 
death of brain cells, involuntary eye movements, and may impair speech, 
hearing, and vision. Long-term exposure to toluene by 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 have been exposed to high levels of 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 by 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 to determine its carcinogenic potential.
    Short-term inhalation of high levels of mixed xylenes (a mixture of 
three closely-related compounds) by 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 include labored breathing, heart palpitation, severe 
chest pain, abnormal heart functioning, and possible effects on the 
blood and kidneys. Developmental effects have been reported in animals 
from xylene exposure via inhalation. Not enough information exists to 
determine the carcinogenic potential of mixed xylenes.
    Short-term inhalation of high levels of n-hexane by 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 to high levels of n-hexane by humans has 
been reported to 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 to determine its carcinogenic potential.
    The EPA estimates that the NESHAP will reduce HAP emissions from 
those impacted HAP emission points in the oil and natural gas 
production source category by 77 percent and will reduce HAP emissions 
from impacted glycol dehydration units in the natural gas transmission 
and storage source category by 95.0 percent.

B. Technical Basis of Regulations

    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 that reflect the maximum degree of reduction in HAP emissions 
through application of maximum achievable control technology (MACT). 
Further, the EPA is required to 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 final 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.
    Prior to proposal, 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. These companies provided 
information on their representative facilities.
    This information was used, in part, as the technical basis for 
determining the MACT level of control for the emission points covered 
under the final standards. In addition to information collected in the 
questionnaires, the EPA considered information available in the general 
literature, information submitted by industry on technical issues 
subsequent to the questionnaire responses, and additional information 
received during the public comment period for the proposed rules, in 
developing the final rules.

C. Stakeholder and Public Participation

    In the development of these final standards, numerous 
representatives of the oil and natural gas production industry, the 
natural gas transmission and storage industry, and other interested 
parties were consulted. Industry representatives 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 for evaluating HAP 
emissions and air emission controls for the final standards.
    The standards for the oil and natural gas production and natural 
gas transmission and storage source categories were proposed in the 
Federal Register on February 6, 1998 (63 FR 6288). The preamble to the 
proposed standards described the rationale for the proposed standards. 
Public comments were solicited at the time of proposal. To provide 
interested parties the opportunity for oral presentation of data, 
views, or arguments concerning the proposed standards, a public hearing 
was offered at proposal. However, the public did not request a hearing 
and, therefore, one was not held. The public comment period was from 
February 6, 1998 to April 7, 1998. Fifty comment letters were received. 
Commenters included industry representatives, trade associations, State 
agencies, and other interested parties.
    On January 15, 1999, in response to comments received on the 
proposal, the EPA also published a supplemental notice announcing the 
availability of additional data collected from facilities in the 
natural gas transmission and storage source category (64 FR 2611). Four 
comment letters were received from industry representatives and trade 
associations.
    All of the comments were carefully considered and changes were made 
to the proposed standards when determined by the EPA to be appropriate. 
A detailed discussion of these comments and responses can be found in a 
document entitled ``National Emissions Standards for Hazardous Air 
Pollutants for Source Categories: Oil and Natural Gas Production and 
Natural Gas Transmission and Storage--Background Information for Final 
Standards: Summary of Public Comments and Responses'' (BID volume 2), 
which is

[[Page 32613]]

referenced in the ADDRESSES section of this preamble (EPA-453/R/99-
004b, May 1999). The summary of comments and responses in the BID 
volume 2 serves as the basis for the revisions that have been made to 
the standards between proposal and promulgation. Section V of this 
preamble discusses the major changes.

III. Summary of Promulgated Standards

A. Promulgated Standards for Oil and Natural Gas Production for Major 
Sources

    This final action amends title 40, chapter I, part 63 of the Code 
of Federal Regulations by adding a new Subpart HH--National Emission 
Standards for Hazardous Air Pollutants from Oil and Natural Gas 
Production Facilities. The standards apply to owners and operators of 
facilities that process, upgrade, or store (1) hydrocarbon liquids 
(with the exception of those facilities that exclusively handle black 
oil) to the point of custody transfer and (2) natural gas from the well 
up to and including the natural gas processing plant. The standards 
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.
    As required by the Act, the determination of a facility's potential 
to emit HAP and, therefore, its status as a major source, is based on 
the total of all HAP emissions from all activities at a facility, 
except that section 112(n)(4) of the Act prohibits aggregating 
emissions from oil or gas exploration or production wells (and their 
associated equipment) and emissions from pipeline compressor or pump 
stations with emissions from other similar units. A definition of 
associated equipment is contained in the final standards.
    To determine potential emissions for determining major source 
status, the final standards specify that an owner or operator that can 
document a decline in annual production each year for 5 years prior to 
the effective date of the rule must calculate the maximum facility 
throughput as the average of the annual throughput for the 3 years 
prior to the effective date of the rule, multiplied by 1.2. If any 
increase in production is observed over the 5 years prior to the 
effective date of the rule, the owner or operator must calculate the 
maximum facility throughput as the maximum annual throughput over the 5 
years prior to the effective date times 1.2. The owner or operator must 
recalculate the maximum throughput if actual annual throughput 
increases to a rate above the calculated values. In addition, for other 
parameters used to estimate emissions, the owner or operator must use 
the maximum value measured over the period for which the maximum 
throughput is calculated and may be determined as an annual average or 
the highest single measured value.
1. Applicability
    The final standards for oil and natural gas production facilities 
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, or a combination of both. In addition, the owner or operator 
of a natural gas processing plant that is a major source of HAP is 
required to reduce HAP emissions from equipment leaks by establishing a 
leak detection and repair (LDAR) program.
    The following are exempt from the requirements of subpart HH:
     Owners and operators of facilities that exclusively 
process, handle, and store black oil are not subject to the final 
standards. Black oil is defined in the final rule as a hydrocarbon 
liquid with an initial gas-to-oil ratio (GOR) less than 0.31 cubic 
meters per liter (m3/liter) and an American Petroleum 
Institute (API) gravity less than 40 degrees. For this subpart, a 
facility that uses natural gas for fuel or generates gas from black oil 
still qualifies for this exemption.
     Oil and natural gas production facilities prior to the 
point of custody transfer that have a facilitywide actual annual 
average natural gas throughput less than 18.4 thousand cubic meters per 
day (m3/day), and a facilitywide actual annual average 
hydrocarbon liquid throughput less than 39,700 liters per day (liter/
day.) Oil and natural gas production facilities after the point of 
custody transfer, including natural gas processing plants, do not 
qualify for these exemptions.
2. Glycol Dehydration Unit Process Vent Standards
    The MACT standard for process vents on new and existing glycol 
dehydration units was set at the floor level of control. To determine 
the MACT floor, the EPA divided glycol dehydration units into two 
sizes: (1) small glycol dehydration units with actual annual average 
natural gas throughputs less than 85 thousand m3/day or with 
actual average benzene emissions less than 0.90 Mg/yr, and (2) large 
glycol dehydration units with actual annual average natural gas 
throughputs equal to or greater than 85 thousand m3/day or 
with actual average benzene emissions equal to or greater than 0.90 Mg/
yr. For small glycol dehydration units, the EPA determined that the 
MACT floor was no control and that it was not cost effective to select 
a regulatory alternative beyond the floor.
    For large glycol dehydration units, the EPA reviewed the 
information that was available to develop a MACT floor (a detailed 
discussion of the development of the MACT floor can be found in the 
docket, Air Docket A-94-04). This information consisted of data 
gathered from: (1) industry responses to the EPA's Air Emission Survey 
Questionnaires, (2) site visits, (3) meetings with stakeholders, and 
(4) literature.
    As required under section 112(d) of the Act, the EPA developed the 
MACT floor based on ``* * * the average limitation achieved by the best 
performing 12 percent of the existing sources * * *.'' The EPA obtained 
information on 200 glycol dehydration units that were considered to be 
major sources of HAP (prior to control). Of these, 34 percent (67 
units) were controlled using a variety of control technologies, 
including: condensation, combustion, and a combination of condensation 
and combustion. The types of control technologies used by the industry 
have been demonstrated, in other applications, to achieve varying 
levels of emission reduction (ranging from 95.0 to 98 percent or 
better). The EPA could not identify a technical basis for the variation 
in the performance levels achieved by the controls reported to be used 
to control process vents on glycol dehydration units. In order to 
account for the variability in HAP emission reduction efficiencies, the 
EPA selected 95.0 percent as the required emission reduction (i.e., the 
MACT floor) for large glycol dehydration units in the oil and natural 
gas production source category.
    The final standards require that all process vents on new and 
existing 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, on 
an annual average basis; or (2) the actual average benzene emissions 
from the glycol dehydration unit are less than 0.90 Mg/yr. Glycol 
dehydration units that meet these criteria are not subject to the 
control requirements of subpart HH.
    Glycol dehydration units that are subject to the control 
requirements are required to connect, through a closed-vent system, 
each process vent on the glycol dehydration unit to an air

[[Page 32614]]

emission control system. The control system must reduce emissions: (1) 
by 95.0 percent or more of HAP, (2) to an outlet concentration of 20 
parts per million by volume (ppmv) or less (for combustion devices), or 
(3) to a benzene emission level of 0.90 Mg/yr or less. Pollution 
prevention measures, such as process modifications or combinations of 
process modifications and one or more control devices that reduce the 
amount of HAP emissions generated, are allowed as an alternative 
provided they achieve the required emission reductions.
3. Storage Vessel Standards
    Final standards are established for existing and new storage 
vessels with the potential for flash emissions that are located at 
major HAP sources. Storage vessels with the potential for flash 
emissions are defined as those that contain a hydrocarbon liquid with a 
storage tank GOR equal to or greater than 0.31 m3/liter, an 
API gravity equal to or greater than 40 degrees, and an actual annual 
average throughput of hydrocarbon liquids equal to or greater than 
79,500 liter/day.
    Flash emissions from storage vessels 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 final standards require 
that storage vessels with the potential for flash emissions be equipped 
with an air emission control system.
    Under the final standards, a storage vessel with the potential for 
flash emissions is required to be equipped with a cover vented through 
a closed-vent system to a control device that (1) recovers or destroys 
HAP emissions with an efficiency of 95.0 percent or greater, or (2) for 
combustion devices, reduces HAP emissions to an outlet concentration of 
20 ppmv or less.
    A pressurized storage vessel that is designed to operate as a 
closed system is considered in compliance with the promulgated 
requirements for storage vessels. In addition, owners or operators that 
are meeting the requirements of 40 CFR part 60, subpart Kb; 40 CFR part 
63, subpart G; or 40 CFR part 63, subpart CC, are also considered in 
compliance.
4. Standards for Equipment Leaks
    The final rule requires owners and operators of natural gas 
processing plants that are major HAP sources to control HAP emissions 
from leaks from ancillary equipment and compressors that contain or 
contact a liquid or gas that has a total volatile hazardous air 
pollutant (VHAP) concentration equal to or greater than 10 percent by 
weight. The final equipment leak standards do not apply to ancillary 
equipment and compressors that operate in VHAP service less than 300 
hours per year. Also, an owner or operator that is subject to and 
controlled under the provisions of 40 CFR part 60, subpart KKK; or 40 
CFR part 61, subpart V; or 40 CFR part 63, subpart H, is only required 
to comply with the requirements of that subpart.
    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 where necessary, perform equipment modifications. 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 (1) at a nonfractionating facility that processes less than 
283 thousand m3/day, or (2) on the Alaskan North Slope, are 
exempt from some of the routine LDAR monitoring requirements. In 
addition, reciprocating compressors in wet gas service are exempt from 
the compressor requirements.
5. Air Emission Control Equipment Requirements
    Specific performance and operating requirements are included for 
each control device installed by the owner or operator. Control devices 
are required to reduce the mass content of the gases vented to the 
device (1) by 95.0 percent or greater by weight as total organic 
compounds (TOC), less methane and ethane, or total HAP; or (2) for 
combustion devices, to an outlet HAP or TOC concentration of 20 ppmv or 
less.
    Closed vent systems that contain bypass devices that could divert 
vent streams away from the control device must either install a flow 
indicator or secure the bypass valve in the nondiverting position to 
ensure that the control device is not bypassed.
    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 installed on storage vessels.
6. Test Methods and Procedures
    An owner or operator must be able to demonstrate that the criteria 
for exemptions from control requirements are met when controls are not 
applied or when existing controls are adequate to meet the exemption 
criteria. For example, owners or operators of glycol dehydration units 
that do not install air emission controls because the actual average 
benzene emission rate from the unit is less than 0.90 Mg/yr must be 
able to demonstrate that the actual average benzene emission rate from 
the unit is less than 0.90 Mg/yr.
    Procedures for demonstrating the HAP emission reduction efficiency 
of control devices and HAP concentration are consistent with procedures 
established in previously promulgated NESHAP that apply to emission 
sources similar to those addressed in the final standards. Engineering 
calculations, modeling (using EPA-approved models), and previous test 
results are generally acceptable means of demonstrating compliance, 
except where such means are not conclusive. Test procedures are 
specified in the final rule for use when testing is required to 
demonstrate compliance.
    An alternative test procedure is provided to demonstrate control 
efficiency 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 the detection of 
leaks from ancillary equipment and compressors and leaks in covers and 
closed vent systems.
7. Monitoring and Inspection Requirements
    The final standards require that the owner or operator periodically 
inspect and monitor air emission control equipment. Periodic 
inspections are 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 is required to 
periodically perform these inspections to determine and ensure that 
these equipment operate with no leaks.
    For covers, the owner or operator is required to perform initial 
and semiannual visual inspections. For closed vent systems, the owner 
or operator is required to perform an initial leak inspection and 
annual visual inspections to detect leaks. In addition, the owner or 
operator of closed vent system components that are not permanently or 
semi-permanently sealed must perform annual leak inspections.
    The final standards require continuous monitoring of control device 
operation through the use of automated instrumentation. Continuous 
monitoring systems measure and record control

[[Page 32615]]

device operating parameters to ensure compliance with the standards.
8. Recordkeeping and Reporting Requirements
    The recordkeeping and reporting requirements associated with the 
final standards are primarily those specified in the part 63 General 
Provisions (40 CFR 63, subpart A). Major sources are subject to all of 
the requirements of the General Provisions with the exception that (1) 
owners or operators are allowed up to 1 year from the effective date of 
the standards to submit the initial notification described in 
Sec. 63.9(b) of subpart A; and (2) owners or operators are allowed to 
submit Periodic reports and startup, shutdown, and malfunction reports 
semiannually instead of quarterly. The EPA selected these specific 
exceptions due to the large number of facilities that need to submit 
notifications or reports related to the NESHAP. The EPA believes that 
these exceptions will not adversely affect the implementation of the 
final regulation or reduce its impact on HAP emissions.

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

    The final standards 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 apply to owners and operators of facilities that process, 
upgrade, transport or store natural gas prior to delivery to a local 
distribution company (LDC) or a final end user if no LDC is present. A 
compressor station that transports natural gas to a natural gas 
processing plant is considered a part of the oil and natural gas 
production source category.
    A facility's potential to emit is required to be calculated based 
on a maximum facility throughput. For storage facilities or facilities 
that store and transport natural gas, the final rule specifies 
procedures for calculating this maximum throughput based on the 
facility's maximum withdrawal and injection rates and the working gas 
capacity of the storage field. Facilities that only transport natural 
gas are required to calculate maximum throughput as the highest annual 
throughput over 5 years prior to the effective date of the rule, 
multiplied by 1.2. The owner or operator must also establish maximum 
values of other parameters required to calculate emissions over the 
same period used to determine maximum throughput.
1. Applicability
    The final standards for natural gas transmission and storage 
facilities require that the owner or operator of a major source of HAP 
reduce HAP emissions from glycol dehydration units through the 
application of air emission control equipment or pollution prevention 
measures, or a combination of both. The owner or operator of a facility 
that processes less than 28.3 thousand m3/day of natural gas 
facilitywide on an actual annual average basis, where glycol 
dehydration units are the only HAP emission points, is exempt from the 
requirements of subpart HHH.
2. Glycol Dehydration Unit Process Vent Standards
    The MACT standard for process vents on new and existing glycol 
dehydration units was set at the floor level of control. To determine 
the MACT floor, the EPA divided glycol dehydration units into two 
sizes: (1) small glycol dehydration units with actual annual average 
natural gas throughputs less than 283 thousand m3/day or 
with actual average benzene emissions less than 0.90 Mg/yr, and (2) 
large glycol dehydration units with actual annual average natural gas 
throughputs equal to or greater than 283 thousand m3/day or 
with actual average benzene emissions equal to or greater than 0.90 Mg/
yr. As discussed in the January 15, 1999 supplemental notice (64 FR 
2611), the EPA determined that the MACT floor for large glycol 
dehydration units was 95.0 percent control. For small glycol 
dehydration units, the EPA determined that the MACT floor was no 
control and that it was not cost effective to select a regulatory 
alternative beyond the floor.
    The final standards require that all process vents on new and 
existing glycol dehydration units that are located at major HAP sources 
be controlled unless (1) the actual annual average flowrate of natural 
gas to the glycol dehydration unit is less than 283 thousand 
m3/day, or (2) the actual average benzene emissions from the 
glycol dehydration unit are less than 0.90 Mg/yr.
    Glycol dehydration units that are subject to the control 
requirements are required to connect, through a closed-vent system, 
each process vent on the glycol dehydration unit to an air emission 
control system that reduces emissions: (1) by 95.0 percent or more of 
HAP, (2) to an outlet HAP concentration of 20 ppmv or less, for 
combustion devices, or (3) to a benzene emission level of 0.90 Mg/yr or 
less. As with the final standards for the oil and natural gas 
production NESHAP, pollution prevention measures, such as process 
modifications (or combinations of process modifications and control 
devices) that reduce the amount of HAP emissions generated, are allowed 
as an alternative provided they achieve the required emission 
reductions.
3. Air Emission Control Equipment Requirements
    Specific performance and operating requirements are included for 
each control device installed by the owner or operator. Control devices 
are required to reduce the mass content of the gases vented to the 
device (1) by 95.0 percent or greater by weight as TOC, less methane 
and ethane, or total HAP; or (2) for combustion devices, to an outlet 
HAP or TOC concentration of 20 ppmv or less.
    Closed vent systems that contain bypass devices that could divert 
vent streams away from the control device must either install a flow 
indicator or secure the bypass valve in the nondiverting position to 
ensure that the control device is not bypassed.
4. Test Methods and Procedures
    An owner or operator must be able to demonstrate that the criteria 
for exemptions from control requirements are met when controls are not 
applied or when existing controls are adequate to meet the exemption 
criteria. For example, owners or operators of glycol dehydration units 
that do not install air emission controls because the actual average 
benzene emission rate from the unit is less than 0.90 Mg/yr must be 
able to demonstrate that the actual average benzene emission rate from 
the unit is less than 0.90 Mg/yr.
    Procedures for demonstrating the HAP emission reduction efficiency 
of control devices and HAP concentration are consistent with procedures 
established in previously promulgated NESHAP that apply to emission 
sources similar to those addressed in the final standards. Engineering 
calculations, modeling (using EPA-approved models), and previous test 
results are generally acceptable means of demonstrating compliance, 
except where such means are not conclusive. Test procedures are 
specified in the final rule for use when testing is required to 
demonstrate compliance.
    An alternative test procedure is provided to demonstrate control 
efficiency 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

[[Page 32616]]

associated with testing the inlet to a condenser in this application. 
Procedures and test methods are also specified for detection of leaks 
in closed-vent systems.
5. Monitoring and Inspection Requirements
    The monitoring and inspection requirements are (1) periodic control 
equipment monitoring, (2) initial leak detection inspections for 
closed-vent systems to ensure all fittings are leak-tight, (3) annual 
visual inspections of closed-vent systems (closed vent system 
components that are not permanently or semi-permanently sealed are also 
required to be annually inspected for leaks), and (4) continuous 
monitoring of control device operation. Continuous monitoring requires 
the use of automated instrumentation that measures and records control 
device compliance operating parameters.

C. Recordkeeping and Reporting Provisions

    The recordkeeping and reporting requirements associated with the 
final standards are primarily those specified in the part 63 General 
Provisions (40 CFR 63, subpart A). Major sources are subject to all of 
the requirements of the General Provisions, except that (1) owners or 
operators are allowed up to 1 year from the effective date of the 
standards to submit the initial notification required under 
Sec. 63.9(b) of subpart A and (2) owners or operators are allowed to 
submit Periodic reports and startup, shutdown, and malfunction reports 
semiannually instead of quarterly. These exceptions were selected to 
maintain consistency between the major source provisions of the final 
regulations for natural gas transmission and storage facilities and oil 
and natural gas production facilities.

IV. Summary of Impacts

A. HAP Emission Reductions

    For major sources, the EPA estimated that the final oil and natural 
gas production standards for existing sources will 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 standards.
    Table 1 presents the major source emission reductions, in addition 
to other environmental, energy, and cost impacts, that the EPA 
estimates will occur from the implementation of the standards for oil 
and natural gas production.

    Table 1.--Summary of Estimated Environmental, Energy, and Economic Impacts Existing and New Major Sources
----------------------------------------------------------------------------------------------------------------
                                                                                                     Existing
                                                                   Existing oil     New oil and     natural gas
                         Impact category                            and natural     natural gas    transmission
                                                                  gas production    production     and storage *
----------------------------------------------------------------------------------------------------------------
Estimated number of impacted facilities.........................             440              44               7
Emission reductions (Mg/yr):
    HAP.........................................................          30,000           3,000             390
    VOC.........................................................          61,000           6,100             610
    Methane.....................................................           7,000             700             230
Secondary environmental emission increases (Mg/yr):
    Sulfur oxides...............................................              <1              <1              <1
    Nitrogen oxides.............................................              <5              <1              <1
    Carbon monoxide.............................................              <1              <1              <1
Energy (Kilowatt hours per year)................................          38,000           3,800            None
Implementation costs (Million of July 1993 $):
    Total installed capital.....................................             6.5             0.7            0.28
    Total annual................................................             4.0             0.4             0.3
----------------------------------------------------------------------------------------------------------------
* No new major sources are anticipated for this source category after the effective date for new sources and in
  the first 3 years following promulgation of the rule.

    The EPA estimates that the final natural gas transmission and 
storage standards for existing sources will result in a reduction of 
HAP emissions from 2,100 Mg/yr to 1,710 Mg/yr. No new major sources are 
anticipated in the first 3 years after promulgation of this NESHAP. 
Table 1 also presents the major source emission reductions, in addition 
to other environmental, energy, and cost impacts, that the EPA 
estimates will occur from the implementation of the standards for 
existing natural gas transmission and storage facilities.
    The air emission reductions achieved by these 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.

B. Secondary Environmental Impacts

    Other environmental impacts are those associated with operation of 
certain air emission control devices. The EPA's secondary air emissions 
impact analyses for the oil and natural gas production source category 
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 safely utilize the non-
condensable vapor streams from condenser systems as an alternative fuel 
source. An option for these facilities is to combust these vapors by 
flaring, rather than installing condensers.
    These limitations are reflected in the analyses conducted by the 
EPA. In the analyses, the EPA estimated that (1) 45 percent of all 
impacted production 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. The secondary air impacts are associated with flare 
operations.

[[Page 32617]]

    The adverse secondary air impacts would be minimal in comparison to 
the primary HAP reduction benefits from the implementation of the 
control options for major 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 standards is 
estimated to be less than 1.0 Mg/yr for both sulfur oxide 
(SOX) and carbon monoxide (CO) and less than 5 Mg/yr for 
nitrogen oxides (NOX). These estimates are for major oil and 
natural gas production sources.
    The anticipated increases in secondary air pollutant emissions are 
based on six affected facilities utilizing flares and are estimated to 
be less than 1.0 Mg/yr for SOX, CO, and NOX, 
each, from the implementation of the 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 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 standards.

C. Energy Impacts

    Energy impacts are those energy requirements associated with the 
operation of emission control devices. The EPA estimated that the 
operation of add-on control devices (e.g., condensers, flares, etc.) 
would not require additional energy. Vapor collection and redirect 
systems used for the control of emissions from a fixed-roof storage 
vessel require electricity for operation of the primary components of 
the system, including fans and blowers.
    The EPA estimated that the annual energy requirements for each 
vapor collection/recovery system installed to comply with the oil and 
natural gas production storage vessel standards are estimated to be 300 
kilowatt hours per year (kW-hr/yr). The EPA also estimated that 
approximately 125 oil and natural gas production major source 
facilities would install this control option. The national energy 
demand increase for existing sources was estimated to be 38,000 kW-hr/
yr.
    Because storage vessels are not regulated under the natural gas 
transmission and storage NESHAP, the EPA estimated that there would be 
no national energy demand increase from the operation of any of the 
control options analyzed under the natural gas transmission and storage 
standards for major sources.
    The 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 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 rule for 
existing major sources in the oil and natural gas production source 
category is approximately $6.5 million. The total capital cost for new 
major sources is estimated to be approximately $700,000.
    The total estimated net annual cost to industry to comply with the 
requirements for existing major sources in the oil and natural gas 
production source category is approximately $4.0 million per year. The 
total net annual cost for new major sources is approximately $400,000 
per year. These estimated annual costs include (1) the cost of capital; 
(2) operating and maintenance costs; (3) the cost of monitoring, 
recordkeeping, and reporting (MRR); and (4) any associated product 
recovery credits.
    The estimated total capital cost to comply with the rule for major 
sources in the natural gas transmission and storage source category is 
approximately $280,000.
    The total estimated net annual cost to industry to comply with the 
requirements for major sources in the natural gas transmission and 
storage source category is approximately $300,000. 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 MRR, and (4) any associated 
product recovery credits.

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 profitability. Price and output changes as 
a result of the regulation are less than 0.0005 of 1 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 $4.6 million, 
which 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. Significant Comments and Changes to the Proposed Standards

    In response to comments received on the proposed standards, several 
changes have been made to the final rules. While several of these 
changes are clarifications designed to clarify the Agency's original 
intent, a number of them are significant changes to the proposed 
standard requirements. A summary of the substantive comments and/or 
changes made since proposal are described in the following sections. 
Detailed Agency responses to public comments and the revised analysis 
for the final rule are contained in the BID, volume 2 (EPA-453/R-99-
004b, May 1999) and docket (see ADDRESSES section of this preamble).

A. Definition of Facility

    The EPA developed the proposed definition of facility to (1) 
identify criteria that define a grouping of emission points that meet 
the intent of the language contained in section 112(a)(1) of the Act: 
``* * * located within a contiguous area and under

[[Page 32618]]

common control, * * *''; and (2) contain terms that are meaningful and 
easily understood within the regulated industries. The proposed 
definition was based on individual surface sites and the idea 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 tract) shall not be aggregated. In addition, the proposed 
definition of a production field facility was limited to glycol 
dehydration units and storage vessels with the potential for flash 
emissions. The EPA requested comments on the proposed definition of 
facility. Specifically, the EPA requested 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 whether another definition would better implement this intent.
    Several commenters responded to the EPA's request for comments on 
the definition of facility. The commenters requested clarification of, 
or suggested changes to, the proposed definition of facility. The 
commenters were primarily concerned that large groupings of equipment 
would inappropriately be considered a part of the same facility, 
resulting in a major source determination. In particular, the 
commenters were concerned about how subparts HH and HHH would treat 
units, contiguous surface sites, and surface sites with equipment under 
separate ownership. The commenters requested clarification of the 
definition of facility to prevent this confusion.
    The EPA intended that the 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.
    The EPA believes that it would not be reasonable to aggregate 
emissions from surface sites that are located on the same lease, but 
are great distances apart. The definition of facility states that 
equipment located on different oil and natural gas properties (e.g., 
leases) are not to be aggregated. Although units (which are made up of 
more than lease or tract) are under common control, under the 
definition of facility, the equipment located on different leases 
contained within each unit would not be aggregated.
    Under section 112(a)(1) of the Act, a major source is defined as 
``* * * any stationary source or group of stationary sources located 
within a contiguous area and under common control.* * *'' The EPA 
believes that by defining facility based on individual surface sites, 
the EPA has provided relief for individual surface sites that are 
located on the same lease, but are far apart, and excluding contiguous 
surface sites located on the same lease would be contrary to the intent 
of the Act.
    Finally, the terms contained in the definition of facility (e.g., 
surface site and lease) are well understood within the industry and by 
enforcement agencies, and the EPA does not believe that additional 
definitions or clarifications regarding these terms are necessary.
    In response to comments regarding specific clarification to the 
definition of facility, the EPA has made several changes to the 
definition of facility. The EPA modified the definition of facility to 
point to the definition of ``surface site.'' In subpart HHH, the EPA 
has added a definition of ``surface site,'' and modified the definition 
of facility to point to the new definition of ``surface site.''
    The EPA further modified the definition of facility in subpart HH 
by: (1) specifying that ``upgraded'' means ``the removal of impurities 
or other constituents to meet contract specifications''; (2) changing 
the term ``unit areas'' to ``surface unit areas''; and (3) specifying 
that separate surface sites, whether or not connected by a road, 
waterway, power line or pipeline, would not be considered a part of the 
same facility.
    Commenters recommended that the EPA expand its definition of 
production field facility in subpart HH to include additional HAP 
emission points beyond glycol dehydration units and storage vessels 
with flash emission potential. The concern was that several facilities 
that could otherwise be major sources of HAP would be exempt from 
subpart HH under the proposed definition of facility.
    One of the EPA's objectives was to develop a definition of facility 
that would comply with section 112(n)(4) of the Act and at the same 
time, reduce the burden on owners and operators in making a major 
source determination. The EPA's evaluation of HAP emission sources in 
production field operations suggested that other potential HAP emission 
points at these facilities (e.g., equipment leaks) would be 
inconsequential to the determination of a facility's major source 
status. The EPA believes that eliminating the need to quantify HAP 
emissions from small sources at production field facilities would not 
affect the major source status determination, but would reduce the 
burden on owners or operators.
    Other commenters requested that the EPA clarify, within the 
definition of facility in subpart HHH, whether the EPA intended to 
exclude facilities used to store natural gas after the gas enters the 
local distribution system of a gas utility. The commenter recommended 
that the EPA clarify that the definition of facility applies all the 
way to the end user only if there is no local distribution company.
    The affected source in the natural gas transmission and storage 
source category should run all the way to the end user only if there is 
no local distribution company. Therefore, the EPA modified the 
definition of facility in subpart HHH to state that if there is not a 
local distribution company, the facility runs to the end user.
    Some commenters were concerned that the definition of facility in 
subpart HH suggests that a natural gas storage facility could qualify 
as a production facility, since natural gas storage takes place in 
depleted gas wells, and liquids are transferred for processing to the 
plant.
    Subpart HH contains a definition of field natural gas which means 
``* * * natural gas that is extracted from a production well prior to 
entering the first stage of processing, such as dehydration.'' In 
addition, a production well is defined in Sec. 63.761 as a ``* * * hole 
drilled in the earth from which * * * field natural gas is extracted.'' 
Since the gas handled by a natural gas storage facility has been 
dehydrated, the EPA believes that the natural gas handled by a storage 
facility would not be considered field natural gas. Therefore, given 
the definitions of production well and field natural gas, a natural gas 
storage field that uses a depleted gas well for storage would not 
qualify as a production facility. The EPA does not believe that 
clarification of the definition of facility is necessary in response to 
this comment.

B. Definition of ``Associated Equipment''

    Section 112(n)(4)(A) of the Act states:

* * * 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 or 
gas exploration or production well (with its associated equipment), 
such emissions shall not be aggregated for any purpose under this 
section.


[[Page 32619]]


According to the statutory definition of major source in section 
112(a)(1) of the Act, HAP emissions from all emission points within a 
contiguous area and under common control must be counted in a major 
source determination. By stating that emissions from any oil and gas 
production and exploration well (with its associated equipment) cannot 
be aggregated for a major source determination, the provisions of 
section 112(n)(4)(A) mean HAP emissions from each well and each piece 
of equipment considered to be associated with the well must be 
evaluated separately in a major source determination. That is, any well 
or piece of associated equipment would only be determined to be a major 
source if HAP emissions from that well or piece of associated equipment 
were major.
    Therefore, to implement this special provision of the Act for the 
oil and natural gas production source category, a definition of 
``associated equipment'' was necessary. However, a definition for the 
term ``associated equipment'' was not provided in the statute. The EPA 
proposed 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 the 
potential for flash emissions would not be associated equipment. In 
developing this proposed definition, the Agency identified and 
evaluated several options. The Agency also sought and received input 
from industry and other stakeholders.
    In the proposal, the EPA specifically requested comments on the 
proposed definition of ``associated equipment.'' The EPA requested that 
commenters disagreeing with the proposal provide alternative definition 
options, along with supporting documentation, that would provide the 
relief that Congress intended for this industry in section 112(n)(4), 
while preserving the EPA's ability to regulate HAP emissions from 
glycol dehydration units and storage vessels with the potential for 
flash emissions.
    Several commenters responded to the EPA's request for comments on 
the EPA's interpretation of the term ``associated equipment'' as used 
in section 112(n)(4) of the Act. Although several commenters did not 
fully support the EPA's interpretation of section 112(n)(4), they 
acknowledged that the proposed definition of associated equipment is a 
workable solution in comparison to other options for this definition. 
According to the commenters, aggregation of glycol dehydration units 
and storage vessels with flash emission potential would result in the 
same major source determination as aggregation of all potential 
sources, but would reduce the burden on the facility operator. Other 
commenters argued that section 112(n)(4) mandates no aggregation of 
emissions from individual sources at oil and gas production fields, and 
that the EPA exceeded its statutory authority by allowing for the 
aggregation of emissions from glycol dehydration units and storage 
vessels with the potential for flash emissions.
    After consideration of these comments, the EPA agrees with those 
commenters who supported the proposed definition as a workable 
solution, and is promulgating the definition as proposed. The EPA 
disagrees with those commenters who argued that the Agency exceeded its 
statutory authority for the reasons discussed below.
    Section 112(a)(1) generally requires HAP emission points within a 
contiguous area and under common control to be aggregated in a major 
source determination for the purposes of section 112. While this 
approach is appropriate for facilities in most industries, it may lead 
to unreasonable aggregations if strictly applied to oil and natural gas 
field operations. Given that some oil and natural gas operations (e.g., 
a production field) may cover several square miles or that leases and 
mineral rights agreements give some companies control over a large area 
of contiguous property, determination of major source status strictly 
by the language of section 112(a)(1) could mean in this industry that 
HAP emissions must be aggregated from emission points separated by 
large distances.
    Congress addressed the unique aspects of the oil and natural gas 
production industry by providing the special provisions in section 
112(n)(4) of the Act referring to the ``* * * oil and gas exploration 
and production well (and its associated equipment) * * *.'' However, 
Congress did not provide a definition of the term ``associated 
equipment'' in the statutory language, leaving its interpretation to 
the EPA. A definition of this term is important in determining the 
major source status of facilities in both the oil and natural gas 
production and the natural gas transmission and storage source 
categories.
    In the absence of clear guidance in the statute, the EPA evaluated 
various options for defining ``associated equipment'' prior to 
proposal. The EPA's objective was to arrive at a reasonable 
interpretation that would (1) provide substantive meaning to the term 
``associated equipment'' consistent with congressional intent; (2) 
prevent the aggregation of small, scattered HAP emission points in 
major source determinations; (3) be easily implementable; and (4) not 
preclude the aggregation of significant HAP emission points in the 
source category. Due to the lack of clarity in the statute and the 
potential impact on major source determinations, the Agency worked with 
industry stakeholders to identify and evaluate options prior to 
proposal. Industry representatives expressed their goals for the 
interpretation of associated equipment, and provided information on the 
magnitude of HAP emission points and the potential impacts of various 
options considered by the EPA.
    The EPA considered, but rejected, a definition based on a narrow 
interpretation that would include only valves and fittings on a well as 
being associated equipment primarily because this option would not 
provide any additional relief to industry beyond what would have been 
provided had Congress only used the term ``well'' in section 112(n)(4) 
of the Act. The EPA also rejected a definition, initially recommended 
by industry, that was based on a broad interpretation that would 
include equipment far beyond the well as associated equipment.
    In discussions with industry stakeholders over an extended period 
of time prior to proposal, the Agency sought to reach a workable 
solution on the definition of associated equipment, one that recognized 
the need to implement relief for this industry as Congress intended, 
and that also allowed for the appropriate regulation of significant 
emission points. In a technical evaluation, the EPA identified glycol 
dehydration units and storage tanks with flash emission potential as 
substantial contributors to HAP emissions, particularly relative to 
sources such as production wells. This conclusion was supported by 
industry. Under the proposed approach, associated equipment was defined 
as all equipment up to the point of custody transfer, excluding glycol 
dehydration units and storage vessels with the potential for flash 
emissions. This approach also included a definition of facility in the 
rule that effectively limited the distance over which all emission 
points (including glycol dehydration units and storage vessels with the 
potential for flash emissions) may be aggregated. Based on discussions 
with industry prior to proposal, as well as comments received 
supporting the proposed definition of associated equipment, the Agency 
believes that the proposed approach

[[Page 32620]]

best meets both industry and EPA goals for implementation of the 
language of section 112(n)(4).
    Commenters who argued that the Agency exceeded its authority with 
the definition of associated equipment offered no substantive new 
information to support their claim. The EPA could not find support in 
the statute or in the legislative history that indicated that Congress 
intended to preclude aggregation of all emission points, including such 
significant ones as glycol dehydration units and storage tanks with 
flash emission potential through their inclusion as associated 
equipment. Rather, there are clear indications, in the EPA's judgement, 
that Congress' primary intent was to preclude the aggregation of small 
emitting sources over vast distances. The legislative history of the 
Act, for example, indicates that Congress believed that oil and natural 
gas production wells and their ``associated equipment'' generally have 
low HAP emissions, and are typically located in widely dispersed 
geographic areas, rather than being concentrated in a single area. The 
EPA used this background as a guide in developing an interpretation of 
``associated equipment'' along with available data on HAP emissions 
from emission points within the oil and natural gas production source 
category. The EPA believes that glycol dehydration units and storage 
vessels with the potential for flash emissions are not the type of 
small HAP emission points that Congress intended to be included in the 
definition of associated equipment.
    After the EPA's review and consideration of all comments received 
on the proposal, the definition of associated equipment promulgated in 
today's rule is the same as proposed.

C. Applicability

1. Black Oil Definition
    In the proposed subpart HH, the EPA provided an exemption from the 
subpart for facilities that exclusively handle black oil. Black oil was 
defined in subpart HH as a hydrocarbon liquid with an API gravity less 
than 40 degrees and a GOR less than 0.31 m3/liter of liquid.
    Several commenters questioned the EPA's basis for the black oil 
definition. The commenters requested that the EPA revise the GOR and 
API gravity cutoffs. One commenter stated that it was unclear whether 
the definition of black oil, with the proposed cutoffs, was a 
determination related to human health risk.
    During the development of the proposal, representatives of the oil 
and natural gas production industry stressed that their industry was 
composed of large numbers of facilities that handle black oil, and that 
black oil was not a significant contributor to overall source category 
HAP emissions. The EPA reviewed the available information and agreed 
with the industry representatives that facilities that exclusively 
handle black oil are not significant contributors to overall HAP 
emissions from the source category. Furthermore, the EPA did not 
identify control technologies, designed to reduce HAP, in use at 
existing facilities that exclusively process, handle, or store black 
oil. Therefore, the EPA determined that the MACT floor for black oil 
facilities was no control. This determination was not made based on the 
health risks associated with black oil.
    The EPA developed the proposed definition of black oil based on a 
series of technical articles that describe five basic hydrocarbon 
fluids that typically exist in a reservoir: black oil, volatile oil, 
retrograde gas, wet gas, and dry gas (Air Docket A-94-04). Of these, 
black oil and volatile oil exist as liquid in the reservoir. Black oil, 
which is a mixture of chemical species ranging from methane to large, 
heavy, nonvolatile organic molecules, is in solution with dry gas, 
which is primarily methane. Volatile oil, which contains fewer heavy 
molecules, is in solution with retrograde gas, which has fewer of the 
heavy organic molecules.
    According to these articles, reservoir fluid types are determined 
by rules-of-thumb based on an initial producing GOR, stock-tank liquid 
gravity, and stock tank liquid color. In particular, fluid type is 
usually determined by initial producing GOR and confirmed by stock tank 
gravity values and stock tank color. (Note: The distinction between 
initial producing GOR and producing GOR is important. As reservoir 
pressure reduces over time, the producing GOR for black oil increases. 
Therefore, if any other GOR is used, the facility may not appear to 
qualify for the exemption.) The rule-of-thumb for volatile oil is an 
initial producing GOR of 0.31 m\3\/liter. Volatile oil is also 
suspected if the API gravity is equal to or greater than 40 degrees and 
a color that is brown, reddish, orange, or green. The rule-of-thumb for 
black oil is an initial producing GOR less than 0.31 m\3\/liter, an API 
gravity of less than 45 degrees, and a color that is dark, usually 
black (sometimes with a greenish cast) or brown.
    Since color determination is subjective, the EPA selected initial 
producing GOR and API gravity as quantifiable criteria for defining 
black oil. In addition, since there is a gap between the rule-of-thumb 
API gravity criteria for black oil and volatile oil, the EPA selected 
the lower, more conservative value of 40 degrees. The EPA believes that 
using a higher API gravity to define black oil, such as 45 or 50 
degrees as recommended by the commenters, would increase the 
possibility that the liquid is a volatile oil, thus exempting sources 
that are likely to have higher HAP emissions. The EPA believes that the 
criteria for defining a black oil, which were obtained directly from 
widely recognized definitions of black oil and volatile oil used in the 
oil and natural gas industry, are technically sound for identifying 
which sources are included as black oil facilities. Therefore, the EPA 
has not modified the black oil definition.
2. Potential-to-Emit
    Several commenters were concerned with the methods used to 
determine whether or not a facility was a major source. In particular, 
the EPA received several comment letters regarding the calculation of a 
facility's potential-to-emit (PTE) when determining a facility's major 
source status. The EPA received comments regarding the calculation of 
PTE on the following issues: (1) potential emissions calculated to 
determine major source status should consider controls and operational 
limitations whether or not they are federally enforceable as specified 
in the National Mining Congress v. EPA (59 F.3d.1351, D.C. Cir. 1995) 
court case; (2) potential emissions should not be based on equipment 
operating capacity because it would result in overregulation, but 
should consider the inherent operating limitations of the facility 
(e.g., declining production levels over time); (3) the EPA should 
provide a simplified approach to calculate PTE, which takes into 
account design and operational limitations; and (4) the EPA should use 
the logic in the PTE Transition policy where sources with low emissions 
may be considered nonmajor if records of actual emissions are 
maintained.
    a. Use of Limitations in Calculating PTE. The EPA received comments 
requesting that potential emissions calculated to determine major 
source status should consider controls and operational limits whether 
or not they are federally enforceable.
    The EPA believes that by referring to the definition of PTE in 
Sec. 63.2 of subpart A, subparts HH and HHH contain the provisions for 
accounting for control

[[Page 32621]]

devices and federally enforceable operating limitations as requested by 
the commenters.
    With respect to the National Mining court case, the court required 
the EPA to reconsider the Federal enforceability requirement, but did 
not vacate the requirement. As a result, the requirement for Federal 
enforceability is still in effect. The definition of PTE for the NESHAP 
program (40 CFR 63.2) is currently under review, and the EPA is engaged 
in a rulemaking process to amend the requirements in the General 
Provisions. The EPA has not modified subparts HH and HHH in response to 
these comments.
    b. Use of Inherent Design and Operational Limitations in 
Calculating PTE. Several commenters were concerned that PTE estimates, 
as defined in the General Provisions, would be unrealistically high and 
would subject many small insignificant sources to the NESHAP 
requirements. The commenters requested that PTE be based on the 
inherent design and operational limitations of production and 
transmission and storage facilities, such as throughput rates.
    According to commenters, the throughput of oil and natural gas 
production operations declines over time, and existing equipment is 
often designed, constructed and operated based on high initial 
production rates. Therefore, the commenters suggested that the 
facilities are usually operated at actual throughput rates that are 
much lower than the design capacities.
    The EPA agrees that there are certain inherent throughput 
limitations associated with the production of oil and natural gas, 
primarily related to declining production rates. Therefore, the final 
subpart HH specifies a method for calculating maximum facility 
throughput to determine major source status and applicability to 
subpart HH. This method is based on a facility's past production rate 
and ability to document declining annual operations. However, it is the 
responsibility of the owner or operator to be aware of changes that 
could require a facility to recalculate its PTE and to do so in a 
timely manner. The owner or operator could be found in violation back 
until the point in time at which an engineering judgement would have 
shown that the facility was reasonably capable of emitting at major 
source thresholds. A detailed discussion is presented in section 2.1.1 
of the BID volume 2.
    The EPA also received comments that the EPA should consider the 
seasonal operation of natural gas storage facilities in estimating 
potential emissions, and that the facility's PTE cannot be based on 
withdrawal for the entire season at maximum capacity. The commenters 
explained that natural gas storage facilities must spend part of the 
year injecting gas, and that withdrawal rates decrease as the storage 
field's pressure drops.
    The EPA agrees that natural gas storage facilities have inherent 
limitations due to the nature of their operations. Therefore, the final 
rule (subpart HHH) contains a method for calculating maximum facility 
throughput to determine major source status and applicability of 
subpart HHH. The method is based on the maximum withdrawal and 
injection rates and the working gas capacity for a given storage field. 
A more detailed discussion is presented in section 2.1.1 of BID volume 
2.
    c. Simplified Approach to Calculate PTE. Several commenters 
recommended a simplified approach to calculating PTE, such as screening 
equations similar to those developed for other NESHAP, to take into 
account design and operational limitations.
    The EPA evaluated the use of an equation similar in structure to 
the Gasoline Distribution NESHAP, 40 CFR part 63, subpart R. After 
extended effort, the EPA found that the number of variables was too 
extensive to allow development of a manageable equation. The EPA also 
received supplemental comments from industry and trade associations 
indicating that their efforts in developing such an equation resulted 
in the same outcome (Air Docket A-94-04).
    Therefore, as an alternative, the EPA developed a simplified major 
source determination (MSD) for HAP emission sources in the oil and 
natural gas production and natural gas transmission and storage source 
categories. The simplified MSD allows the owner or operator of a 
facility to easily determine (1) if they are major sources and whether 
NESHAP requirements apply to their facility, and (2) if they are 
required to obtain a title V operating permit.
    Therefore, the final subpart HH states that facilities, prior to 
the point of custody transfer, that have a facilitywide actual annual 
average natural gas throughput less than 18.4 thousand m3/
day and a facilitywide actual annual average hydrocarbon liquid 
throughput less than 39,700 liter/day are exempt from subpart HH. A 
more detailed discussion on the development of this MSD is presented in 
section 2.1.1 of the BID volume 2.
    Owners and operators of production facilities, after the point of 
custody transfer (including natural gas processing plants), must 
aggregate emissions from all HAP emissions units at the facility when 
determining whether or not the facility is a major source. Production 
facilities, after the point of custody transfer, are likely to have 
emission units in addition to glycol dehydration units and storage 
vessels, such as amine treaters and sulfur recovery units that are 
typically located at natural gas processing plants. Since these 
emissions units must be included in the total emissions for the 
facility, the EPA could not develop a cutoff that would reasonably 
ensure that sources operating below such a cutoff would not be major 
sources. Therefore, production facilities located after the point of 
custody transfer, including natural gas processing plants, do not 
qualify for the simplified major source determination.
    Using the same procedure, the EPA developed an MSD for natural gas 
transmission and storage facilities where glycol dehydration units are 
the only HAP emission points. The final subpart HHH states that natural 
gas transmission and storage facilities operating with an actual annual 
average natural gas throughput below 28.3 thousand m3/day 
are exempt from subpart HHH.
    d. Use of PTE Transition Policy. Under the EPA's 1995 Potential to 
Emit Transition Policy, sources with low emissions (e.g., less than 50 
percent of major source thresholds) may be deemed nonmajor if records 
of actual emissions are kept. Several commenters suggested the use of 
written documentation of physical and operational limitations that 
would be federally, State, or otherwise practically enforceable.
    In the January 25, 1995 policy memorandum entitled ``Options for 
Limiting the Potential to Emit (PTE) of a Stationary Source Under 
Section 112 and Title V of the Clean Air Act (Act),'' the EPA issued a 
transition policy for section 112 and title V. The transition policy 
addressed concerns that some sources may face gaps in the ability to 
acquire federally enforceable PTE limits because of delays in State 
adoption or EPA approval of programs or in their implementation. In 
order to ensure that such gaps would not create adverse consequences 
for States or for sources, the EPA provided that, during a 2-year 
period extending from January 1995 through January 1997, sources 
lacking federally enforceable limitations, State and local air 
regulators had the option of treating the following types of sources as 
non-major under section 112 and in their title V programs: (1) sources 
that maintain adequate records to demonstrate that their actual 
emissions

[[Page 32622]]

are less than 50 percent of the applicable major source threshold and 
have continued to operate at less than 50 percent of the threshold 
since January 1994, and (2) sources with actual emissions between 50 
and 100 percent of the major source threshold but which hold State-
enforceable limits that are enforceable as a practical matter. On 
August 27, 1996, the transition policy was extended until July 31, 
1998. On July 10, 1998, in a memorandum entitled ``Second Extension of 
January 25, 1995 Potential to Emit Transition Policy and Clarification 
of Interim Policy,'' the EPA announced a second extension of the 
transition policy. The extensions were provided because the EPA is 
engaged in a rulemaking process to consider amendments to the current 
PTE requirements. Currently, the PTE rulemaking, which will address the 
PTE requirements in the General Provisions (40 CFR part 63, subpart A) 
and the title V operating permits program, has not been completed. 
Those rule amendments will affect federal enforceability requirements 
for PTE limits under these programs. Thus, there will continue to be 
uncertainty with respect to federally enforceable limits. Therefore, in 
the July 10, 1998 memorandum, the EPA extended the transition policy 
until December 31, 1999, or until the effective date of the final rule 
in the PTE rulemaking, whichever is sooner.
    The EPA expects that the rulemaking will be completed before 
December 31, 1999, and owners and operators will have the option of 
complying with the PTE rulemaking as well as the procedures specified 
in subparts HH and HHH.

D. Glycol Dehydration Unit Process Vent Standards

    The proposed standards required a 95.0 percent control efficiency 
for all control devices, but did not specify over which averaging 
period the 95.0 percent should be determined. By not specifying an 
averaging period, the proposed rule required continuous compliance for 
all control devices. The EPA received several comment letters 
requesting that the EPA specify an averaging period. The commenters 
were particularly concerned that condensers could not achieve a 95.0 
percent control efficiency on a continuous basis and that additional 
controls would be required to ensure compliance with the 95.0 percent 
requirement.
    The commenters' primary point was that condensers are significantly 
affected by changes in ambient temperature. According to the 
commenters, when the ambient temperature is high, the condensers are 
less efficient. The commenters were concerned that during the warm 
summer months, condensers would not meet the control requirements. 
Therefore, the commenters specifically requested either a 30-day or a 
12-month averaging period for compliance with the control requirements 
to balance changes in ambient temperature. In support of this request, 
the commenters maintained that using a longer averaging period would 
create no significant change in the emissions to the environment, but 
would substantially decrease the number of technical violations of the 
standard and reduce the administrative burden for the industry and the 
EPA.
    The EPA reviewed the control efficiency and averaging period 
requirements in response to these comments. Based on the Agency's 
review of the possible options, today's rules require 95.0 percent 
control as a daily average. As an alternative for owners or operators 
that install condensers, the EPA has modified subpart HH to allow 95.0 
percent condenser control as a 365-day rolling average, based on daily 
average condenser efficiency as a function of condenser outlet 
temperature (i.e., at the end of each operating day, the owner or 
operator calculates the daily average condenser outlet temperature, 
then calculates the 365-day average control efficiency for the 
preceding 365 days, including the current operating day).
    Based on the information collected under the authority of section 
114 of the Act, the comments received during the public comment period, 
and site visits, the EPA believes that an averaging period shorter than 
365 days is appropriate for the natural gas transmission and storage 
source category. To the Agency's knowledge, glycol dehydration units 
located at storage facilities do not typically operate throughout the 
year. Therefore, the EPA was concerned that it would take more than 1 
calendar year for a facility to obtain 365 days of data. Additionally, 
glycol dehydration units located at these sources do not typically 
operate during the warm summer months when condenser efficiency is 
lower. Although transmission facilities do operate for most of the 
year, the EPA believes that the HAP emission units in operation at 
these facilities are primarily compressors, and that most glycol 
dehydration units located at these facilities are used for withdrawing 
natural gas from storage (i.e., not likely to operate year-round). 
Therefore, for condensers installed on glycol dehydration units subject 
to control requirements under subpart HHH, the EPA has modified the 
requirements to specify that owners or operators that install 
condensers have the option of meeting a 95.0 percent control efficiency 
as a 30-day rolling average.
    Several commenters requested that the EPA allow for combinations of 
controls and process modifications to achieve the required control 
efficiency. The commenters provided several suggestions for modifying 
the language in Sec. 63.765(c)(2) stating that the owner or operator 
could reduce emissions from the glycol dehydration unit by 95.0 percent 
through process modifications or process modifications with controls. 
In addition, one of the suggestions was to include language allowing 
the owner or operator to complete a one-time compliance demonstration 
for the process modification.
    The EPA agrees that owners or operators should be allowed to 
achieve a 95.0 percent emission reduction using process modifications 
or combinations of process modifications and one or more control 
devices. Therefore, today's rules contain requirements for 
demonstrating compliance with a 95.0 percent emission reduction using 
process modifications or a combination of process modifications and one 
or more control devices. In particular, the final rule requires the 
owner or operator to demonstrate how emissions have been reduced and to 
what level, and that the facility continues to be operated such that 
the 95.0 percent emission reduction is maintained.
    The EPA does not believe that a one-time compliance demonstration 
would ensure future or continuous compliance, and the EPA believes that 
it is not appropriate. Therefore, the EPA has not included the 
commenter's suggested language allowing a one-time compliance 
demonstration for process modification. Instead, the final rules 
require the owner or operator to document facility operations and to 
provide this information in the Periodic reports.

E. Storage Vessel Standards

    The criteria for an API gravity equal to or greater than 40 degrees 
or an initial producing GOR equal to or greater than 0.31 m3/liter were 
used in the proposed rule to define storage vessels with the potential 
for flash emissions. Prior to proposal, the EPA's analysis of storage 
vessels that contain hydrocarbon liquids that have an API gravity or an 
initial producing GOR higher than these criteria indicated the 
potential for significant flash emissions.

[[Page 32623]]

    The EPA received comment letters objecting to the proposed cutoffs 
for storage vessels with the potential for flash emissions. In order to 
demonstrate their objection to the technical basis for these exemption 
criteria, the commenters provided emissions estimates for tanks 
containing hydrocarbon liquids with an API gravity less than 40 degrees 
and GOR of less than 0.31 m3/liter. According to the 
emission estimates, these tanks, which do not meet the criteria for a 
storage vessel with the potential for flash emissions and would be 
exempt from the storage vessel control requirements, had significant 
HAP emissions. The EPA also received emission estimates for a tank 
containing a hydrocarbon liquid with an API gravity greater than 40 
degrees and a GOR greater than 0.31 m3/liter. According to 
the analysis provided by the commenter, this tank would be subject to 
the storage vessel control requirements but had no flash emissions.
    The commenters did not provide alternative suggestions for defining 
storage vessels with the potential for flash emissions, other than 
recommending that ``the proposed storage tank exemption/control 
criteria be based on credible engineering methods supported by 
fundamental principles of fluid phase behavior.''
    The EPA developed the definition for storage vessels with the 
potential for flash emissions based on criteria (i.e., API gravity and 
GOR) that were easily recognized by industry personnel and relatively 
easy to obtain. Furthermore, these criteria are based on hydrocarbon 
liquid characteristics.
    According to section 112(d)(1), the Administrator is required to 
establish emission standards for each category of major sources. 
Section 112(d)(1) states that ``[T]he Administrator may distinguish 
among classes, types, and sizes of sources within a category or 
subcategory in establishing such standards * * *.'' Furthermore, 
section 112(d)(3) states that emission standards for existing sources 
in a category may be no less stringent than the MACT floor.
    As stated in section V.C.1 of this preamble, the EPA has 
established that among the class of sources referred to as black oil 
facilities, the MACT floor is no control. For the class of sources 
defined as storage vessels with the potential for flash emissions 
(which includes storage vessels that do not process black oil), the EPA 
evaluated `` * * * the average emission limitation achieved by the best 
performing 12 percent of the existing sources (for which the 
Administrator has emissions information) * * * '' (section 112(d)(3)(A) 
of the Act). The EPA determined that the top 12 percent of existing 
storage vessels with the potential for flash emissions were controlled.
    The EPA recognizes that there could be specific situations, such as 
the ones analyzed by the commenters, where emissions of an exempted 
stream are higher than those of a non-exempted stream. In addition, 
there are many factors that affect whether flash emissions occur (e.g., 
pressure drop between two tanks, liquid vapor pressure, etc.). However, 
the EPA believes that this approach identifies hydrocarbon liquids that 
have a potential for significant flash emissions under conditions 
representative of industry operations.
    In today's rule (final subpart HH), the EPA has added the 
throughput cutoff criterion to the storage vessels with the potential 
for flash emissions definition. The final rule states that a storage 
vessel with the potential for flash emissions is defined as a storage 
vessel that contains a hydrocarbon liquid with a stock tank GOR equal 
to or greater than 0.31 m3/liter and an API gravity equal to or greater 
than 40 degrees, and an actual annual average hydrocarbon liquid 
throughput equal to or greater than 79,500 liter/day. By adding the 
throughput criterion to the definition of storage vessels with the 
potential for flash emissions, rather than as a cutoff specified in 
proposed Sec. 63.764(c)(2), storage vessels that do not meet the 
criteria for a storage vessel with the potential for flash emissions 
are not considered affected sources in the final rule and are not 
included in a facility's PTE calculation for determining major source 
status. The EPA believes that based on representative industry 
operations, the 40 degrees, 0.31 m3/liter and the 79,500-
liter/day exemption criteria are appropriate for defining storage 
vessels with the potential for flash emissions.

F. Standards for Natural Gas Transmission and Storage

    The EPA received several comment letters expressing concern for the 
EPA's proposed standard for the natural gas transmission and storage 
source category. The commenters stated that the EPA did not have 
sufficient data to develop standards for the natural gas transmission 
and storage source category. The commenters requested that the EPA 
delay the natural gas transmission and storage portion of the proposed 
rulemaking to properly survey the industry for more meaningful data and 
assess whether a standard for the natural gas transmission and storage 
source category is necessary or achievable.
    Several commenters explained that a review of the background 
information for proposed subpart HHH showed that the database consisted 
of information on the methods used in natural gas transmission from 
only two companies and no underground storage facilities. The 
commenters noted that the companies surveyed were predominately oil 
production facilities that handled gas as a by-product of oil 
production and that have higher HAP emissions because they handle more 
liquids with higher concentrations of HAP.
    In response to these comments, the EPA collected additional data on 
glycol dehydration units in the natural gas transmission and storage 
source category through site visits and requests for information under 
the authority of section 114 of the Act.
    Through these site visits and survey questionnaires, the EPA 
collected information from 83 facilities in the natural gas 
transmission and storage source category. The EPA considered this new 
information, along with the previously collected information on the 
natural gas transmission and storage source category, in developing a 
MACT floor for existing and new process vents on glycol dehydration 
units located at facilities in this source category. The EPA also used 
this information to better characterize processes and operations at 
natural gas transmission and storage facilities.
    As stated in the January 15, 1999 supplemental notice (64 FR 2611), 
the additional data supported a MACT floor of 95.0 percent for existing 
and new natural gas transmission and storage facilities. In addition, 
the EPA announced that the Agency was considering raising the proposed 
throughput cutoff of 85 thousand
m3/day to 283 thousand m3/day on an actual annual 
average basis. Glycol dehydration units operating below this cutoff 
would not be required to install controls under subpart HHH. The data 
did not warrant a change in the benzene emission cutoff of 0.90 Mg/yr.
    The public comment period closed on February 16, 1999. The EPA 
received four comment letters in response to the EPA's request for 
comments and supporting information on the consideration of a 95.0 
percent HAP emission reduction as the floor level of control, on the 
283 thousand m3/day natural gas throughput cutoff and the 
0.90-Mg/yr benzene emission cutoff. The commenters agreed that 
exempting glycol dehydration units with actual annual average natural 
gas throughputs

[[Page 32624]]

less than 283 thousand 78m3/day and with actual average 
benzene emissions less than 0.90 Mg/yr from the control requirements 
under subpart HHH was appropriate.
    However, the commenters indicated that they did not agree with a 
MACT floor of 95.0 percent for the transmission and storage source 
category. The commenters requested that the final rule should either 
exempt existing sources controlled by condensers, or require that 
existing sources controlled with condensers be controlled to a 
different level (i.e., 70 percent) than the combustion technology-based 
MACT floor. The commenters stated that condensers could consistently 
achieve a 75 percent emission reduction and that requiring an 
additional 20 percentage points of emission reduction in HAP would be 
inconsistent with the cost-to-benefit analysis in the February 6, 1998 
proposal.
    The EPA does not believe that it is necessary to provide exemptions 
or alternative levels of control for existing glycol dehydration units 
that are controlled by condensers. The EPA believes that this would not 
be consistent with the Act, which specifies in section 112(d)(3) that 
for a source category with 30 or more sources (such as the transmission 
and storage source category), the MACT floor for existing sources shall 
not be less stringent than `` * * * the average limitation achieved by 
the best performing 12 percent of the existing sources * * *.'' The 
data collected by the EPA indicated that the average limitation 
achieved by the top 12 percent of the existing glycol dehydration units 
located at natural gas transmission and storage facilities was 95.0 
percent. Furthermore, the data indicated that the top 12 percent of the 
existing glycol dehydration units were controlled using combustion or a 
combination of combustion and condensation. Therefore, in accordance 
with the statute, the EPA established the MACT floor to be 95.0 percent 
for glycol dehydration units located at natural gas transmission and 
storage facilities, which corresponds to combustion.
    However, the EPA agrees that the supplemental notice did not 
address the issue of averaging period for condensers in use at 
transmission and storage facilities. As stated in this preamble, the 
final rule allows an owner or operator that installs a condenser for 
control of HAP from glycol dehydration unit process vents to establish 
compliance with the 95.0 percent HAP emission reduction on a 30-day 
rolling average. In addition, the final rule allows the owner or 
operator to comply with one of the following: (1) 95.0 percent HAP 
emission reduction, (2) 20 ppmv outlet HAP concentration for combustion 
devices, or (3) outlet emissions of 0.90 Mg/yr of benzene. The EPA 
believes that the 0.90 Mg/yr benzene emission limit and the 30-day 
averaging period for condensers provides sufficient flexibility for 
owners and operators of existing controlled glycol dehydration units. A 
more detailed discussion regarding the EPA's responses to the comments 
received on the supplemental notice are presented in the BID volume 2.

G. Monitoring, Recordkeeping, and Reporting Requirements

    The EPA received several comment letters claiming that the 
recordkeeping and reporting requirements of the proposed rule were 
extremely burdensome. The commenters requested that the EPA reduce the 
monitoring, recordkeeping, and reporting burden associated with the 
proposed rule. In particular, commenters were concerned that remote and 
unmanned facilities would be overburdened by the proposed monitoring, 
recordkeeping and reporting requirements. Commenters also requested 
that provisions be added to the rule to avoid duplicative reporting. 
Other commenters requested that flexibility to allow alternative 
monitoring, recordkeeping, and reporting be incorporated into the final 
rule.
    The EPA recognizes that unnecessary monitoring, recordkeeping, and 
reporting requirements would burden both the source and enforcement 
agencies. Prior to proposal, the EPA attempted to reduce the amount of 
monitoring, recordkeeping, and reporting to only that which is 
necessary to demonstrate compliance.
    Although the EPA has not removed the monitoring requirements for 
unmanned or remote facilities, the EPA did evaluate the possibility of 
reducing the requirements for unmanned facilities. The EPA concluded, 
however, that the monitoring requirements are the minimum necessary to 
ensure that control devices are operating to ensure compliance.
    The EPA reevaluated whether monitoring, recordkeeping, and 
reporting requirements could be further reduced while maintaining the 
enforceability of the rule. Therefore, the EPA has made the following 
changes in the promulgated rule to further reduce the monitoring, 
recordkeeping, and reporting burden.
    (1) Almost all reports have been consolidated into the Notification 
of Compliance Status report and the Periodic reports.
    (2) If multiple tests are conducted for the same kind of emission 
point, using the same test method, only one complete test report is 
required to be submitted along with the summaries of the results of 
other tests.
    (3) Site-specific test plans describing quality assurance in 
Sec. 63.7(c) of 40 CFR part 63, subpart A, are not specifically 
required in the individual subparts because the test methods cited in 
subparts HH and HHH already contain applicable quality assurance 
protocols. It should be noted that the Administrator would still have 
the authority to request a test plan.
    (4) Periodic reports are required to be submitted semiannually for 
all facilities (the proposal required quarterly reports if monitored 
parameters were out of range more than a specified percentage of time).
    (5) A reduction in the record retention requirements for monitored 
parameters. The proposal required values of monitored parameters to be 
recorded every 15 minutes and all 15-minute records had to be retained. 
The final rule requires monitored parameters to be recorded every hour 
and all hourly records to be retained.
    Several commenters were concerned with the provisions specifying 
the accuracy of the measurement devices used to comply with the subpart 
and requested that the EPA change or remove the accuracy requirements.
    The EPA believes that accuracy requirements are necessary to 
demonstrate ongoing compliance. Furthermore, if the accuracy 
requirements were removed, additional recordkeeping and reporting 
requirements would be necessary to ensure that less accurate monitors 
were not installed after the performance tests. However, the EPA agrees 
with the commenters that the accuracy levels could be slightly less 
restrictive. Therefore, the EPA has changed the accuracy levels from 
1 percent of the temperature being monitored, in 
oC or 0.5 oC, to 2 
percent of the temperature being monitored, in oC or 
2.5 oC, whichever is greater.

H. Cost and Economic Impacts

    The EPA specifically requested comments on the cost impact and the 
production recovery credits as discussed in section IV of the preamble 
to the proposal (63 FR 6297), along with supporting documentation. The 
EPA received comment letters stating that the EPA had underestimated 
the costs of controls, had underestimated the cost of treating produced 
water, and had

[[Page 32625]]

overstated the quantity of product recovered that could be sold to 
offset the costs associated with subpart HH. Of specific concern was 
the closure of smaller facilities due to the rule.
    The EPA based its cost estimates for control devices on published 
installed control system costs from the Ventura County (California) Air 
Pollution Control District (APCD) (Air Docket A-94-04). These costs 
were associated with a glycol dehydration unit regulation issued by the 
Ventura County APCD. According to this information, the cost of 
installing a condenser control system does not vary significantly based 
on the size (capacity) of a glycol dehydration system.
    Approximately 20 billion barrels per year of produced water are 
generated by the oil and natural gas production source category (Air 
Docket A-94-04). Using an emission model developed by the Gas Research 
Institute (GRI-GLYCalc, version 3.0) to determine the amount of 
produced water generated by the number of facilities estimated to be 
affected by subpart HH, the EPA calculated that the oil and natural gas 
production NESHAP would result in an increase in produced water 
production of approximately 590,000 barrels per year. A GRI report (GRI 
Publication Number GRI-96/0049) indicated that produced water would be 
typically handled along with other produced water streams, either by 
underground injection control, surface impoundment, or other 
miscellaneous methods. Thus, the EPA believes that the final NESHAP 
would have a minimal impact on existing produced water disposal costs 
and that the estimated NESHAP control costs are, therefore, reasonable.
    The EPA based its national cost estimate impacts on the estimated 
number of facilities that would be impacted by the regulatory 
provisions of subparts HH and HHH, along with detailed emission control 
cost estimates per HAP emission point (Air Docket A-94-04). In 
addition, the monitoring, recordkeeping, and reporting (MRR) costs were 
based on a detailed analysis of the regulatory requirements of subparts 
HH and HHH. The EPA currently believes that the MRR cost estimates 
accurately reflect the estimated effort required to address MRR 
requirements in the final NESHAP.
    Further, the EPA expects that the 85 thousand m3/day 
size cutoff will prevent the premature closure of a large number of 
small and often marginal well operations. Not accounting for this size 
cutoff would contribute to differences in the estimated reduction in 
natural gas production and employment losses associated with the 
standards.
    As described in Section 4 of the economic impact analysis report, 
the EPA's economic model determines production and closure decisions on 
the basis of a producing field (i.e., a group of similar wells) that is 
consistent with commenters concerns that ``production decisions are 
made on a well-by-well or project basis and if an individual project's 
profits fall below its break-even point, that the well will be 
abandoned.'' The EPA did not estimate losses of economically producible 
natural gas reserves. The economic analysis conducted by the EPA is 
unable to address possible impacts on production from future natural 
gas reserves. However, based on the negligible impact on current 
natural gas production associated with the EPA's engineering estimate 
of compliance cost, it is not expected that these impacts would be as 
great as indicated by the commenter.

VI. 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 these rulemakings. The principal purposes of 
the docket are (1) to allow interested parties a means to 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 texts, BID 
volumes 1 and 2, references not readily available to the public, and 
technical memoranda documenting the information considered by the EPA 
in the development of the 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 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. 1788.02 and 1789.02) and copies may be obtained from Sandy Farmer, 
OPPE Regulatory Information Division; U.S. Environmental Protection 
Agency (2137); 401 M Street, SW; Washington, DC 20460 or by calling 
(202) 260-2740. The information requirements are not effective until 
OMB approves them.
    Information is required to ensure compliance with the provisions of 
the final rules. If the relevant information were collected less 
frequently, the EPA would not be reasonably assured that a source is in 
compliance with the final rules. In addition, the EPA's authority to 
take administrative action would be reduced significantly.
    The final rules require that facility owners or operators retain 
records for a period of 5 years, which exceeds the 3 year retention 
period contained in the guidelines in 5 CFR 1320.6. The 5 year 
retention period is consistent with the provisions of the General 
Provisions of 40 CFR part 63, and with the 5 year records retention 
requirement in the operating permit program under title V of the Act.
    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 part 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 
are 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 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 final 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 
484 existing and new (projected) respondents.
    The estimated annual average hour burden for the final natural gas 
transmission and storage NESHAP is 30 hours per respondent. The 
estimated annual average cost of this burden is $1,300 for each of the 
estimated 7 existing respondents.
    Reports are required on a semiannual basis 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

[[Page 32626]]

for a Federal agency. This includes the time needed to review 
instructions; to 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; to adjust the existing ways to comply with any 
previously applicable instructions and requirements; to train personnel 
to be able to respond to a collection of information; to search data 
sources; to 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. 
The EPA is amending the table in 40 CFR part 9 of currently approved 
ICR control numbers issued by OMB for various regulations to list the 
information requirements contained in these final rules.

C. Executive Order 12866: A Significant Regulatory Action Determination

    Under Executive Order 12866, ``Regulatory Planning and Review,'' 
(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.
    Pursuant to Executive Order 12866, OMB has reviewed these rules. 
Changes made in response to OMB suggestions or recommendations are 
documented in the public record.

D. Regulatory Flexibility Act

    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 final 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 the control requirements of the oil and natural 
gas production NESHAP those glycol dehydration units located at major 
sources with (1) an actual flowrate of natural gas to the glycol 
dehydration unit less than 85 thousand m3/day, on an annual 
average basis, or (2) benzene emissions less than 0.90 Mg/yr. Also, 
these considerations include exempting from the control requirements of 
the natural gas transmission and storage NESHAP those glycol 
dehydration units located at major sources with (1) an actual flowrate 
of natural gas to the glycol dehydration unit less than 283 thousand 
m3/day, on an annual average basis; or (2) benzene emissions 
less than 0.90 Mg/yr.
    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 1 
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 1 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).

E. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. The EPA will submit a report containing this rule and 
other required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective June 17, 1999.

F. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandate Reform Act of 1995 (UMRA), Pub. L. 
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 proposed and final rules with ``Federal 
mandates'' that may result in expenditures to State, local, and tribal 
governments, in the aggregate, or to the private sector, of $100 
million or more in any 1 year. Before promulgating 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

[[Page 32627]]

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 today's final rules do not include a 
Federal mandate that may result in expenditures of $100 million of more 
for State, local, and tribal governments, in the aggregate, or the 
private sector in any 1 year. Therefore, the requirements of the 
Unfunded Mandates Reform Act do not apply to today's final rules.

G. Executive Order 12875: Enhancing the Intergovernmental Partnership

    Under Executive Order 12875, the EPA may not issue a regulation 
that is not required by statute and that creates a mandate upon a 
State, local or tribal government unless the Federal government 
provides the funds necessary to pay the direct compliance costs 
incurred by those governments, or the EPA consults with those 
governments. If the EPA complies by consulting, Executive Order 12875 
requires the EPA to provide OMB a description of the extent of the 
EPA's prior consultation with representatives of affected State, local 
and tribal governments, the nature of their concerns, copies of any 
written communications from the governments, and a statement supporting 
the need to issue the regulation. In addition, Executive Order 12875 
requires the EPA to develop an effective process permitting elected 
officials and other representatives of State, local and tribal 
governments to provide meaningful and timely input in the development 
of regulatory proposals containing significant unfunded mandates.
    Today's rules do not create a mandate on the State, local or tribal 
governments. These rules do not impose any enforceable duties on these 
entities. Accordingly, the requirements of Section 1(a) of Executive 
Order 12875 do not apply to these rules. The EPA, nevertheless, 
involved State and local governments in their development of the final 
rules.

H. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045, ``Protection of Children from Environmental 
Health Risks and Safety Risks,'' (62 FR 19885, April 23, 1997) applies 
to any rule that: (1) the EPA determines is economically significant as 
defined under Executive Order 12866, (2) concerns an environmental 
health or safety risks, and (3) the EPA has any reason to believe may 
disproportionately affect children. If the regulatory action meets 
these criteria, the EPA must evaluate the environmental health or 
safety effects of the planned rule on children, and explain why the 
planned regulation is preferable to other potentially effective and 
reasonably feasible alternatives considered by the EPA.
    The EPA interprets Executive Order 13045 as applying only to those 
regulatory actions that are based on health or safety risks, such that 
the analysis required under section 5.501 of the Order has the 
potential to influence the regulation. These rules are not subject to 
Executive Order 13045 for two reasons: (1) the rule is based solely on 
technology performance; and (2) no alternative technologies have been 
identified that would provide greater stringency at a reasonable cost, 
therefore, an assessment of impacts on children would have no impact on 
the stringency decision.

I. Executive Order 13084: Consultation and Coordination With Indian 
Tribal Governments

    Under Executive Order 13084, the EPA may not issue a regulation 
that is not required by statute, that significantly or uniquely affects 
the communities of Indian tribal governments, and that imposes 
substantial direct compliance costs on those communities unless the 
Federal Government provides the funds necessary to pay the direct 
compliance costs incurred by the tribal governments, or the EPA 
consults with those governments. If the EPA complies by consulting, 
Executive Order 13084 requires the EPA to provide to OMB, in a 
separately identified section of the preamble to the rule, a 
description of the extent of the EPA's prior consultation with 
representatives of affected tribal governments, a summary of the nature 
of their concerns, and a statement supporting the need to issue the 
regulation. In addition, Executive Order 13084 requires the EPA to 
develop an effective process permitting elected officials and other 
representatives of Indian tribal governments ``to provide meaningful 
and timely input in the development of regulatory policies on matters 
that significantly or uniquely affect their communities.''
    Today's rules do not significantly or uniquely affect the 
communities of Indian tribal governments. The final rules do not create 
mandates upon tribal governments. Accordingly, the requirements of 
section 3(b) of Executive Order 13084 do not apply to these rules.

J. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act (NTTAA), Pub. L. 104-113 (March 7, 1996), directs all Federal 
agencies to use voluntary consensus standards in regulatory and 
procurement activities unless doing so would be inconsistent with 
applicable law or otherwise impracticable. Voluntary consensus 
standards are technical standards (e.g., materials specifications, test 
methods, sampling procedures, and business practices) developed or 
adopted by one or more voluntary consensus bodies. The NTTAA requires 
Federal agencies to provide Congress, through annual reports to OMB, 
with explanations when an agency does not use available and applicable 
voluntary consensus standards. This section summarizes the EPA's 
response to the requirements of the NTTAA for the analytical and test 
methods required by this final rule.
    Consistent with the NTTAA, the EPA conducted a search to identify 
voluntary consensus standards. The search identified 16 voluntary 
consensus standards that appeared to have possible use in lieu of EPA 
standard reference methods. However, after reviewing available 
standards, the EPA determined that eight of the candidate consensus 
standards identified for measuring HAP or surrogate pollutant emissions 
subject to the emission standards in the rule would not be practical 
due to lack of equivalency, documentation, validation data and other 
important technical and policy considerations. Seven of the remaining 
candidate consensus standards are new standards under development that 
the EPA plans to follow, review, and consider adopting at a later date.
    One consensus standard, ASTM Z7420Z, is potentially practical for 
EPA use in lieu of EPA Method 18 (See 40 CFR part 60, appendix A). At 
the time of the EPA's search, the ASTM standard was still under 
development and the EPA had provided comments on the method. The EPA 
also compared a draft of this ASTM standard to methods previously 
reviewed as alternatives to EPA Method 18 that were approved with 
specific applicability limitations. These methods are designated as 
ALT-017 and CTM-028 and available through EPA's Emission Measurement 
Center Internet site at www.epa.gov/ttn/emc/tmethods.html. The proposed 
ASTM Z7420Z standard is very similar to these approved alternative 
methods. When finalized and adopted by ASTM, the standard may be 
equally suitable for the same applications as the approved

[[Page 32628]]

alternatives. However, this rule does not adopt the ASTM standard since 
it is not practical to do so until the potential candidate is final and 
the EPA has review the final standard. The EPA plans to continue to 
follow the progress of the standard and will consider adopting the ASTM 
standard at a later date.
    Similarly, the Gas Research Institute has developed a sampling 
method for glycol dehydration units, the ``Atmospheric Rich/Lean Method 
for Determining Glycol Dehydrator Emissions'' (GRI-95/0368.1). The 
development of this procedure included a field evaluation program and 
technical review by the EPA. A report documenting this procedure has 
been available to the public from the GRI since 1996. This procedure 
provides a simpler, cheaper, and technically appropriate means of 
determining HAP emissions from glycol dehydration unit process vents 
when direct measurement is necessary. Consistent with the Agency's 
commitment to reduce costs to the private sector where technically 
feasible and in accordance with Clean Air Act requirements, the EPA has 
included the ``Atmospheric Rich/Lean Method for Determining Glycol 
Dehydrator Emissions'' as an alternative control device performance 
test procedure.
    This rule requires standard EPA methods known to the industry and 
States. Approved alternative methods also may be used with prior EPA 
approval.

List of Subjects in 40 CFR Part 63

    Environmental protection, Air pollution control, Hazardous air 
pollutants, Black oil, Associated equipment, Storage vessels with the 
potential for flash emissions, Glycol dehydration units, Oil and 
natural gas production, Natural gas transmission and storage, Equipment 
leaks, Natural gas processing plant, Reporting and recordkeeping 
requirements.

    Dated: May 14, 1999.
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 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., as amended by Pub. L. 101-
549, 104 Stat. 2399.

    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  Startups, shutdowns, and malfunctions.
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 equipment requirements.
63.772  Test methods, compliance procedures, and compliance 
determinations.
63.773  Inspection and monitoring requirements.
63.774  Recordkeeping requirements.
63.775  Reporting requirements.
63.776  Delegation of authority.
63.777  Alternative means of emission limitation.
63.778  [Reserved]
63.779  [Reserved]
Appendix to Subpart HH--Tables

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 and operators of the 
emission points, 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) and either (a)(2) or (a)(3) of 
this section.
    (1) Major sources of hazardous air pollutants (HAP) as determined 
using the maximum natural gas or hydrocarbon liquid throughput, as 
appropriate, calculated in paragraphs (a)(1)(i) through (a)(1)(iii) of 
this section. A facility that is determined to be an area source based 
on emission estimates using the maximum natural gas or hydrocarbon 
throughput calculated as specified in paragraphs (a)(1)(i) through 
(iii) of this section, but subsequently increases emissions or 
potential to emit above the major source levels (without first 
obtaining and complying with other limitations that keep its potential 
to emit HAP below major source levels), becomes a major source and must 
comply thereafter with all applicable provisions of this subpart 
starting on the applicable compliance date specified in paragraph (f) 
of this section. Nothing in this paragraph is intended to preclude a 
source from limiting its potential to emit through other appropriate 
mechanisms that may be available through the permitting authority.
    (i) If the owner or operator documents, to the Administrator's 
satisfaction, a decline in annual natural gas or hydrocarbon liquid 
throughput, as appropriate, each year for the 5 years prior to June 17, 
1999, the owner or operator shall calculate the maximum natural gas or 
hydrocarbon liquid throughput used to determine maximum potential 
emissions according to the requirements specified in paragraph 
(a)(1)(i)(A) of this section. In all other circumstances, the owner or 
operator shall calculate the maximum throughput used to determine 
whether a facility is a major source in accordance with the 
requirements specified in paragraph (a)(1)(i)(B) of this section.
    (A) The maximum natural gas or hydrocarbon liquid throughput is the 
average of the annual natural gas or hydrocarbon liquid throughput for 
the 3 years prior to June 17, 1999, multiplied by a factor of 1.2.
    (B) The maximum natural gas or hydrocarbon liquid throughput is the 
highest annual natural gas or hydrocarbon liquid throughput over the 5 
years prior to June 17, 1999, multiplied by a factor of 1.2.
    (ii) The owner or operator shall maintain records of the annual 
facility natural gas or hydrocarbon liquid throughput each year and 
upon request submit such records to the Administrator. If the facility 
annual natural gas or hydrocarbon liquid throughput increases above the 
maximum natural gas or hydrocarbon liquid throughput calculated in 
paragraph (a)(1)(i)(A) or (a)(1)(i)(B) of this section, the maximum 
natural gas or hydrocarbon liquid throughput must be recalculated using 
the higher throughput multiplied by a factor of 1.2.
    (iii) The owner or operator shall determine the maximum values for 
other parameters used to calculate emissions as the maximum for the 
period over which the maximum natural gas or hydrocarbon liquid 
throughput is determined in accordance with paragraph (a)(1)(i)(A) or 
(B) of this section. Parameters shall be based on either highest 
measured values or annual average.
    (2) Facilities that process, upgrade, or store hydrocarbon liquids 
prior to the point of custody transfer.
    (3) Facilities that process, upgrade, or store natural gas prior to 
the point at which natural gas enters the natural gas

[[Page 32629]]

transmission and storage source category or is delivered to a final end 
user. For the purposes of this subpart, natural gas enters the natural 
gas transmission and storage source category after the natural gas 
processing plant, when present. If no natural gas processing plant is 
present, natural gas enters the natural gas transmission and storage 
source category after the point of custody transfer.
    (b) The affected sources to which the provisions of this subpart 
apply 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) through (4) of this section.
    (1) Each glycol dehydration unit;
    (2) Each storage vessel with the potential for flash emissions;
    (3) The group of all ancillary equipment, except compressors, 
intended to operate in volatile hazardous air pollutant service (as 
defined in Sec. 63.761), which are located at natural gas processing 
plants; and
    (4) Compressors intended to operate in volatile hazardous air 
pollutant service (as defined in Sec. 63.761), which are located at 
natural gas processing plants.
    (c) [Reserved]
    (d) The owner and operator of a facility that does not contain an 
affected source as specified in paragraph (b) of this section are not 
subject to the requirements of this subpart.
    (e) Exemptions. The facilities listed in paragraphs (e)(1) and 
(e)(2) of this section are exempt from the requirements of this 
subpart. Records shall be maintained as required in Sec. 63.10(b)(3).
    (1) 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. For the purposes of this subpart, a black 
oil facility that uses natural gas for fuel or generates gas from black 
oil shall qualify for this exemption.
    (2) A facility, prior to the point of custody transfer, with a 
facilitywide actual annual average natural gas throughput less than 
18.4 thousand standard cubic meters per day and a facilitywide actual 
annual average hydrocarbon liquid throughput less than 39,700 liters 
per day.
    (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 provisions of this subpart no later than June 
17, 2002 except as provided for in Sec. 63.6(i). The owner or operator 
of an area source, the construction or reconstruction of which 
commenced before February 6, 1998, that increases its emissions of (or 
its potential to emit) HAP such that the source becomes a major source 
that is subject to this subpart shall comply with this subpart 3 years 
after becoming a major source.
    (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 initial startup or June 17, 1999, whichever date is 
later. Area sources, the construction or reconstruction of which 
commences on or after February 6, 1998, that become major sources shall 
comply with the provisions of this standard immediately upon becoming a 
major source.
    (g) The following provides owners or operators of an affected 
source with information on overlap of this subpart with other 
regulations for equipment leaks. The owner or operator shall document 
that they are complying with other regulations by keeping the records 
specified in Sec. 63.774(b)(9).
    (1) After the compliance dates specified in paragraph (f) of this 
section, ancillary equipment and compressors that are subject to this 
subpart and that are also subject to and controlled under the 
provisions of 40 CFR part 60, subpart KKK, are 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 and compressors that are subject to this 
subpart and are also subject to and controlled under the provisions of 
40 CFR part 61, subpart V, are 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 and compressors that are subject to this 
subpart and are also subject to and controlled under the provisions of 
40 CFR part 63, subpart H, are only required to comply with the 
requirements of 40 CFR part 63, subpart H.
    (h) An owner or operator of an affected source that is a major 
source or is located at a major source and is subject to the provisions 
of this subpart is also subject to 40 CFR part 70 or part 71 operating 
permit requirements.


Sec. 63.761  Definitions.

    All terms used in this subpart shall have the meaning given them in 
the Clean Air Act (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, pressure relief devices, sampling connection systems, open-ended 
valves, or lines, valves, flanges, or other connectors.
    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.
    Black oil means hydrocarbon (petroleum) liquid with an initial 
producing gas-to-oil ratio (GOR) less than 0.31 cubic meters per liter 
and an API gravity less than 40 degrees.
    Boiler means an enclosed device using controlled flame combustion 
and having the primary purpose of recovering and exporting thermal 
energy in the form of steam or hot water. Boiler also means any 
industrial furnace as defined in 40 CFR 260.10.
    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 one or more control devices. If gas or vapor from 
regulated equipment is routed to a process (e.g., to a fuel gas 
system), the conveyance system 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 organic HAP emissions.
    Condensate means hydrocarbon liquid separated from natural gas that 
condenses due to changes in the temperature, pressure, or both, and

[[Page 32630]]

remains liquid at standard conditions, as specified in Sec. 63.2.
    Continuous recorder means a data recording device that either 
records an instantaneous data value at least once every hour or records 
hourly or more frequent block average values.
    Control device means any equipment used for recovering or oxidizing 
HAP or 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 
(i.e., injected into the flame zone of a combustion device), 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 or closed-vent systems.
    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. 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, but are not limited to, 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, or from storage vessels or automatic transfer facilities or 
other such equipment, including product loading racks, to pipelines or 
any other forms of transportation. For the purposes of this subpart, 
the point at which such liquids or natural gas enters a natural gas 
processing plant is a point of custody transfer.
    Equipment leaks means emissions of HAP from ancillary equipment (as 
defined in this section) and compressors.
    Facility means any grouping of equipment where hydrocarbon liquids 
are processed, upgraded (i.e., remove impurities or other constituents 
to meet contract specifications), or stored prior to the point of 
custody transfer; or where natural gas is processed, upgraded, or 
stored prior to entering the natural gas transmission and storage 
source category. For the purpose of a major source determination, 
facility (including a building, structure, or installation) means oil 
and natural gas production and processing equipment that is located 
within the boundaries of an individual surface site as defined in this 
section. Equipment that is part of a facility will typically be located 
within close proximity to other equipment located at the same facility. 
Pieces of production equipment or groupings of equipment located on 
different oil and gas leases, mineral fee tracts, lease tracts, 
subsurface or surface unit areas, surface fee tracts, surface lease 
tracts, or separate surface sites, whether or not connected by a road, 
waterway, power line or pipeline, shall not be considered part of the 
same facility. Examples of facilities in the oil and natural gas 
production source category include, but are not limited to, well sites, 
satellite tank batteries, central tank batteries, a compressor station 
that transports natural gas to a natural gas processing plant, and 
natural gas processing plants.
    Field natural gas means natural gas extracted from a production 
well prior to entering the first stage of processing, such as 
dehydration.
    Fixed-roof means a cover that is mounted on a 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 
combustion device occupied by the flame envelope.
    Flash tank. See the definition for gas-condensate-glycol (GCG) 
separator.
    Flow indicator means a device which indicates whether gas flow is 
present in a line or whether the valve position would allow gas flow to 
be 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 of 
gas produced per liter of crude oil or other hydrocarbon liquid.
    Glycol dehydration unit means a device in which a liquid glycol 
(including, but not limited to, ethylene glycol, diethylene glycol, or 
triethylene glycol) absorbent directly contacts a natural gas stream 
and absorbs water in a contact tower or absorption column (absorber). 
The glycol contacts and absorbs water vapor and other gas stream 
constituents from the natural gas and becomes ``rich'' glycol. This 
glycol is then regenerated in the glycol dehydration unit reboiler. The 
``lean'' glycol is then recycled.
    Glycol dehydration unit baseline operations means operations 
representative of the glycol dehydration unit operations as of June 17, 
1999. For the purposes of this subpart, for determining the percentage 
of overall HAP emission reduction attributable to process 
modifications, baseline operations shall be parameter values 
(including, but not limited to, glycol circulation rate or glycol-HAP 
absorbency) that represent actual long-term conditions (i.e., at least 
1 year). Glycol dehydration units in operation for less than 1 year 
shall document that the parameter values represent expected long-term 
operating conditions had process modifications not been made.
    Glycol dehydration unit process vent means either the glycol 
dehydration unit reboiler vent and the vent from the GCG separator 
(flash tank), if present.
    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 or to a control device.
    Hazardous air pollutants or HAP means the chemical compounds listed 
in section 112(b) of the Clean Air 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 compliance.
    Hydrocarbon liquid means any naturally occurring, unrefined 
petroleum liquid.
    In VHAP service means that a piece of ancillary equipment or 
compressor either contains or contacts a fluid (liquid or gas) which 
has a total volatile HAP (VHAP) concentration equal to or greater than 
10 percent by weight as determined according to the provisions of 
Sec. 63.772(a).
    In wet gas service means that a piece of equipment contains or 
contacts the field gas before the extraction of natural gas liquids.
    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 is not 
physically formed into one manufactured or assembled unit with the 
combustion section; rather, the energy recovery section is 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 preheat the incoming vent stream or combustion air.

[[Page 32631]]

    Initial producing GOR means the producing standard cubic meters of 
gas per liter at the time that the reservoir pressure is above the 
bubble point pressure (or dewpoint pressure for a gas).
    Initial startup means the first time a new or reconstructed source 
begins production. For the purposes of this subpart, initial startup 
does not include subsequent startups (as defined in this section) of 
equipment, for example, following malfunctions or shutdowns.
    Major source, as used in this subpart, shall have the same meaning 
as in Sec. 63.2, except that: (1) Emissions from any oil or gas 
exploration or production well (with its associated equipment (as 
defined in this section)) and emissions from any pipeline compressor 
station or pump station shall not be aggregated with emissions from 
other similar units, to determine whether such emission points or 
stations are major sources, even when emission points are in a 
contiguous area or under common control; (2) 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 aggregated for a major source determination.
    Natural gas means a naturally occurring mixture of hydrocarbon and 
nonhydrocarbon gases found in geologic formations beneath the earth's 
surface. The principal hydrocarbon constituent is methane.
    Natural gas liquids (NGL) means the liquid hydrocarbons, such as 
ethane, propane, butane, pentane, natural gasoline, and condensate that 
are extracted from field natural gas.
    Natural gas processing plant (gas plant) means any processing site 
engaged in the extraction of natural gas liquids from field gas, or the 
fractionation of mixed NGL to natural gas products, or a combination of 
both.
    No detectable emissions means no escape of HAP from a device or 
system to the atmosphere as determined by:
    (1) Instrument monitoring results in accordance with the 
requirements of Sec. 63.772(c); and
    (2) The absence of 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, indicates that an owner or operator has complied with 
an applicable operating parameter limitation, over the appropriate 
averaging period as specified in Sec. 63.772(f) or (g).
    Operating permit means a permit required by 40 CFR part 70 or part 
71.
    Organic monitoring device means an instrument used to indicate the 
concentration level of organic compounds exiting a control device based 
on a detection principle such as infra-red, photoionization, or thermal 
conductivity.
    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 an enclosed device using a controlled flame, 
the primary purpose of which is to transfer heat to a process fluid or 
process material that is not a fluid, or to a heat transfer material 
for use in a process (rather than for steam generation).
    Produced water means water that is extracted from the earth from an 
oil or natural gas production well, or 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.
    Reciprocating compressor means a piece of equipment that increases 
the pressure of a process gas by positive displacement, employing 
linear movement of the drive shaft.
    Relief device means a device used only to release an unplanned, 
non-routine discharge in order to avoid safety hazards or equipment 
damage. 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 meets both of the following 
conditions: it 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 it 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.
    Shutdown means for purposes including, but not limited to, periodic 
maintenance, replacement of equipment, or repair, the cessation of 
operation of a glycol dehydration unit, or other affected source under 
this subpart, or equipment required or used solely to comply with this 
subpart.
    Startup means the setting into operation of a glycol dehydration 
unit, or other affected equipment under this subpart, or equipment 
required or used to comply with this subpart. Startup includes initial 
startup and operation solely for the purpose of testing equipment.
    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 liquid with a stock tank GOR 
equal to or greater than 0.31 cubic meters per liter and an API gravity 
equal to or greater than 40 degrees and an actual annual average 
hydrocarbon liquid throughput equal to or greater than 79,500 liters 
per day. Flash emissions occur when dissolved hydrocarbons in the fluid 
evolve from solution when the fluid pressure is reduced.
    Surface site means any combination of one or more graded pad sites, 
gravel pad sites, foundations, platforms, or the immediate physical 
location upon which equipment is physically affixed.
    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 an instrument used to monitor 
temperature and having a minimum accuracy of 2 percent of 
the temperature being monitored expressed in  deg.C, or 2.5 
 deg.C, whichever is greater. The temperature monitoring device may

[[Page 32632]]

measure temperature in degrees Fahrenheit or degrees Celsius, or both.
    Total organic compounds or TOC, as used in this subpart, means 
those compounds which can be measured according to the procedures of 
Method 18, 40 CFR part 60, appendix A.
    Volatile hazardous air pollutant concentration or VHAP 
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  Startups, shutdowns, and malfunctions.

    (a) The provisions set forth in this subpart shall apply at all 
times except during startups or shutdowns, during malfunctions, and 
during periods of non-operation of the affected sources (or specific 
portion thereof) resulting in cessation of the emissions to which this 
subpart applies. However, during the startup, shutdown, malfunction, or 
period of non-operation of one portion of an affected source, all 
emission points which can comply with the specific provisions to which 
they are subject must do so during the startup, shutdown, malfunction, 
or period of non-operation.
    (b) The owner or operator shall not shut down items of equipment 
that are required or utilized for compliance with the provisions of 
this subpart during times when emissions are being routed to such items 
of equipment, if the shutdown would contravene requirements of this 
subpart applicable to such items of equipment. This paragraph does not 
apply if the item of equipment is malfunctioning, or if the owner or 
operator must shut down the equipment to avoid damage due to a 
contemporaneous startup, shutdown, or malfunction of the affected 
source or a portion thereof.
    (c) During startups, shutdowns, and malfunctions when the 
requirements of this subpart do not apply pursuant to paragraphs (a) 
and (b) of this section, the owner or operator shall implement, to the 
extent reasonably available, measures to prevent or minimize excess 
emissions to the maximum extent practical. For purposes of this 
paragraph, the term ``excess emissions'' means emissions in excess of 
those that would have occurred if there were no startup, shutdown, or 
malfunction, and the owner or operator complied with the relevant 
provisions of this subpart. The measures to be taken shall be 
identified in the applicable startup, shutdown, and malfunction plan, 
and may include, but are not limited to, air pollution control 
technologies, recovery technologies, work practices, pollution 
prevention, monitoring, and/or changes in the manner of operation of 
the source. Back-up control devices are not required, but may be used 
if available.
    (d) The owner or operator shall prepare a startup, shutdown, or 
malfunction plan as required in Sec. 63.6(e)(3) except that the plan is 
not required to be incorporated by reference into the source's title V 
permit as specified in Sec. 63.6(e)(3)(i). Instead, the owner or 
operator shall keep the plan on record as required by 
Sec. 63.6(e)(3)(v). The failure of the plan to adequately minimize 
emissions during startup, shutdown, or malfunctions does not shield an 
owner or operator from enforcement actions.


Sec. 63.763  [Reserved].


Sec. 63.764  General standards.

    (a) Table 1 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. 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 of HAP emissions shall comply with the standards in this subpart 
as specified in paragraphs (c)(1) through (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 (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 specified in Sec. 63.773; and
    (iii) The owner or operator shall comply with the recordkeeping and 
reporting requirements specified in Secs. 63.774 and 63.775.
    (2) For each storage vessel with the potential for flash emissions 
subject to this subpart, the owner or operator shall comply with the 
requirements specified in paragraphs (c)(2)(i) through (iii) of this 
section.
    (i) The control requirements for storage vessels specified in 
Sec. 63.766;
    (ii) The monitoring requirements specified in Sec. 63.773; and
    (iii) The recordkeeping and reporting requirements specified in 
Secs. 63.774 and 63.775.
    (3) For ancillary equipment (as defined in Sec. 63.761) and 
compressors 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) [Reserved]
    (e) Exemptions. (1) The owner or operator is exempt from the 
requirements of paragraph (c)(1) of this section if the criteria listed 
in paragraph (e)(1)(i) or (e)(1)(ii) are met. Records of the 
determination of these criteria must be maintained as required in 
Sec. 63.774(d)(1) of this subpart.
    (i) The actual annual average flowrate of natural gas to the glycol 
dehydration unit is less than 85 thousand standard cubic meters per 
day, as determined by the procedures specified in Sec. 63.772(b)(1) of 
this subpart; or
    (ii) The actual average emissions of benzene from the glycol 
dehydration unit process vent to the atmosphere are less than 0.90 
megagram per year, as determined by the procedures specified in 
Sec. 63.772(b)(2) of this subpart.
    (2) The owner or operator is exempt from the requirements of 
paragraph (c)(3) of this section for ancillary equipment (as defined in 
Sec. 63.761) and compressors at a natural gas processing plant subject 
to this subpart, if the criteria listed in paragraphs (e)(2)(i) and 
(e)(2)(ii) are met. Records of the determination of these criteria must 
be maintained as required in Sec. 63.774(d)(2) of this subpart.
    (i) Any ancillary equipment and compressors that contain or contact 
a fluid (liquid or gas) must have a total VHAP concentration less than 
10 percent by weight, as determined by the procedures specified in 
Sec. 63.772(a) of this subpart; and
    (ii) That ancillary equipment and compressors must operate in VHAP 
service less than 300 hours per calendar year.
    (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 a 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) [Reserved]
    (h) [Reserved]
    (i) In all cases where the provisions of this subpart require an 
owner or operator to repair leaks by a specified time after the leak is 
detected, it is a violation of this standard to fail to take

[[Page 32633]]

action to repair the leak(s) within the specified time. If action is 
taken to repair the leak(s) within the specified time, failure of that 
action to successfully repair the leak(s) is not a violation of this 
standard. However, if the repairs are unsuccessful, a leak is detected 
and the owner or operator shall take further action as required by the 
applicable provisions of this subpart.


Sec. 63.765  Glycol dehydration unit process vent standards.

    (a) This section applies to each glycol dehydration unit subject to 
this subpart with an actual annual average natural gas flowrate equal 
to or greater than 85 thousand standard cubic meters per day and with 
actual average benzene glycol dehydration unit process vent emissions 
equal to or greater than 0.90 megagrams per year, that must be 
controlled for HAP emissions as specified in Sec. 63.764(c)(1)(i).
    (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 either paragraph (b)(1)(i) or 
(b)(1)(ii) of this section.
    (i) The owner or operator shall connect the process vent to a 
control device or a combination of control devices through a closed-
vent system. The closed-vent system shall be designed and operated in 
accordance with the requirements of Sec. 63.771(c). The control 
device(s) shall be designed and operated in accordance with the 
requirements of Sec. 63.771(d).
    (ii) The owner or operator shall connect the process vent to a 
control device or combination of control devices through a closed-vent 
system and the outlet benzene emissions from the control device(s) 
shall be reduced to a level less than 0.90 megagrams per year. The 
closed-vent system shall be designed and operated in accordance with 
the requirements of Sec. 63.771(c). The control device(s) shall be 
designed and operated in accordance with the requirements of 
Sec. 63.771(d), except that the performance levels specified in 
Sec. 63.771(d)(1)(i) and (ii) do not apply.
    (2) One or more safety devices that vent directly to the atmosphere 
may be used on the air emission control equipment installed to comply 
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 (3) of this section.
    (1) The owner or operator shall control air emissions by connecting 
the process vent to a process natural gas line.
    (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 process vent are reduced by 95.0 percent 
through process modifications, or a combination of process 
modifications and one or more control devices, in accordance with the 
requirements specified in Sec. 63.771(e).
    (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 emissions to the atmosphere 
from the glycol dehydration unit process vent are reduced by one of the 
levels specified in paragraphs (c)(3)(i) through (c)(3)(ii) of this 
section, through the installation and operation of controls as 
specified in paragraph (b)(1) of this section.
    (i) HAP emissions are reduced by 95.0 percent or more.
    (ii) Benzene emissions are reduced to a level less than 0.90 
megagrams per year.


Sec. 63.766  Storage vessel standards.

    (a) This section applies to each storage vessel with the potential 
for flash emissions (as defined in Sec. 63.761) subject to this 
subpart.
    (b) The owner or operator of a storage vessel with the potential 
for flash emissions (as defined in Sec. 63.761) shall comply with one 
of the control requirements specified in paragraphs (b)(1) and (2) of 
this section.
    (1) The owner or operator shall equip the affected storage vessel 
with the potential for flash emissions with a cover that is connected, 
through a closed-vent system that meets the conditions specified in 
Sec. 63.771(c), to a control device or a combination of control devices 
that meets any of the conditions specified in Sec. 63.771(d). The cover 
shall be designed and operated in accordance with the requirements of 
Sec. 63.771(b).
    (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.
    (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) and (2) of this section.
    (d) This section does not apply to storage vessels for which the 
owner or operator is meeting the requirements specified in 40 CFR part 
60, subpart Kb; or is meeting the requirements specified in 40 CFR part 
63, subparts G or CC.


Sec. 63.767  [Reserved].


Sec. 63.768  [Reserved].


Sec. 63.769  Equipment leak standards.

    (a) This section applies to equipment subject to this subpart, 
located at natural gas processing plants and specified in paragraphs 
(a)(1) and (a)(2) of this section, that contains or contacts a fluid 
(liquid or gas) that has a total VHAP concentration equal to or greater 
than 10 percent by weight (determined according to the procedures 
specified in Sec. 63.772(a)) and that operates in VHAP service equal to 
or greater than 300 hours per calendar year.
    (1) Ancillary equipment, as defined in Sec. 63.761; and
    (2) Compressors.
    (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 each compressor 
subject to this section located at an existing or new source, the owner 
or operator shall meet the requirements specified in 40 CFR part 61, 
subpart V, Secs. 61.241 through 61.247, except as specified in 
paragraphs (c)(1) through (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) The owner or operator has obtained permission from the 
Administrator to use an alternative means of emission limitation that 
achieves a reduction in emissions of VHAP at least equivalent to that 
achieved by the control required in this subpart.
    (ii) 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

[[Page 32634]]

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, unless 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 VHAP 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 283,000 standard cubic meters per day or more of 
field gas 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 (3) of 
this section.
    (6) Pumps in VHAP service, valves in gas/vapor and light liquid 
service, and pressure relief devices in gas/vapor service located 
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 (c)(1) through (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 equipment 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 as required by the provisions of this subpart. 
Compliance with paragraphs (b), (c), and (d) of this section will be 
determined by review of the records required by Sec. 63.774 and the 
reports required by Sec. 63.775, by review of performance test results, 
and by inspections.
    (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 form a continuous barrier over the entire surface area of 
the liquid in the tank.
    (2) 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 a 
HAP emissions 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) Properly install, calibrate, maintain, and operate a flow 
indicator at the inlet to the bypass device that could divert the 
stream away from the control device to the atmosphere that takes a 
reading at least once every 15 minutes and sounds an alarm when the 
bypass device is open such that the stream is being, or could be, 
diverted away from the control device to the atmosphere; or
    (B) Secure the bypass device valve installed at the inlet to the 
bypass device in the non-diverting 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 non-diverting position and 
the vent stream is not diverted through the bypass device.
    (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 (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 95.0 percent by weight or greater as 
determined in accordance with the requirements of Sec. 63.772(e); or
    (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 seconds at a 
minimum temperature of 760 deg.C.
    (D) 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 95.0 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) [Reserved]
    (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 Sec. 63.772(e).
    (4) The owner or operator shall operate each control device in 
accordance with the requirements specified in paragraphs (d)(4)(i) and 
(ii) of this section.
    (i) Each control device used to comply with this subpart shall be 
operating at all times when gases, vapors, and fumes are vented from 
the HAP emissions unit or units through the closed-vent system to the 
control device, as required under Secs. 63.765, 63.766, and 63.769, 
except when maintenance or repair on 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.
    (ii) For each control device monitored in accordance with the 
requirements of Sec. 63.773(d), the owner or operator shall demonstrate 
compliance according to

[[Page 32635]]

the requirements of Sec. 63.772(f) or (g), as applicable.
    (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) The spent carbon removed from the carbon adsorption system 
shall be either regenerated, reactivated, or burned in one of the units 
specified in paragraphs (d)(5)(ii)(A) through (d)(5)(ii)(G) of this 
section.
    (A) Regenerated or reactivated in a thermal treatment unit for 
which the owner or operator has been issued a final permit under 40 CFR 
part 270 that implements the requirements of 40 CFR part 264, subpart 
X.
    (B) Regenerated or reactivated in a thermal treatment unit equipped 
with and operating air emission controls in accordance with this 
section.
    (C) Regenerated or reactivated in a thermal treatment unit equipped 
with and operating organic air emission controls in accordance with a 
national emissions standard for HAP under another subpart in 40 CFR 
part 61 or this part.
    (D) Burned in a hazardous waste incinerator for which the owner or 
operator has been issued a final permit under 40 CFR part 270 that 
implements the requirements of 40 CFR part 264, subpart O.
    (E) Burned in a hazardous waste incinerator which the owner or 
operator has designed and operates in accordance with the requirements 
of 40 CFR part 265, subpart O.
    (F) Burned in a boiler or industrial furnace for which the owner or 
operator has been issued a final permit under 40 CFR part 270 that 
implements the requirements of 40 CFR part 266, subpart H.
    (G) Burned in a boiler or industrial furnace which the owner or 
operator has designed and operates in accordance with the interim 
status requirements of 40 CFR part 266, subpart H.
    (e) Process modification requirements. Each owner or operator that 
chooses to comply with Sec. 63.765(c)(2) shall meet the requirements 
specified in paragraphs (e)(1) through (e)(3) of this section.
    (1) The owner or operator shall determine glycol dehydration unit 
baseline operations (as defined in Sec. 63.761). Records of glycol 
dehydration unit baseline operations shall be retained as required 
under Sec. 63.774(b)(10).
    (2) The owner or operator shall document, to the Administrator's 
satisfaction, the conditions for which glycol dehydration unit baseline 
operations shall be modified to achieve the 95.0 percent overall HAP 
emission reduction, either through process modifications or through a 
combination of process modifications and one or more control devices. 
If a combination of process modifications and one or more control 
devices are used, the owner or operator shall also establish the 
percent HAP reduction to be achieved by the control device to achieve 
an overall HAP emission reduction of 95.0 percent for the glycol 
dehydration unit process vent. Only modifications in glycol dehydration 
unit operations directly related to process changes, including, but not 
limited to, changes in glycol circulation rate or glycol-HAP 
absorbency, shall be allowed. Changes in the inlet gas characteristics 
or natural gas throughput rate shall not be considered in determining 
the overall HAP emission reduction.
    (3) The owner or operator that achieves a 95.0 percent HAP emission 
reduction using process modifications alone shall comply with paragraph 
(e)(3)(i) of this section. The owner or operator that achieves a 95.0 
percent HAP emission reduction using a combination of process 
modifications and one or more control devices shall comply with 
paragraphs (e)(3)(i) and (e)(3)(ii) of this section.
    (i) The owner or operator shall maintain records, as required in 
Sec. 63.774(b)(11), that the facility continues to operate in 
accordance with the conditions specified under paragraph (e)(2) of this 
section.
    (ii) The owner or operator shall comply with the control device 
requirements specified in paragraph (d) of this section, except that 
the emission reduction achieved shall be the emission reduction 
specified for the control device(s) in paragraph (e)(2) of this 
section.


Sec. 63.772  Test methods, compliance procedures, and compliance 
demonstrations.

    (a) Determination of material VHAP or HAP concentration to 
determine the applicability of the equipment leak standards under this 
subpart (Sec. 63.769). Each piece of ancillary equipment and 
compressors are presumed to be in VHAP service or in wet gas service 
unless an owner or operator demonstrates that the piece of equipment is 
not in VHAP service or in wet gas service.
    (1) For a piece of ancillary equipment and compressors to be 
considered not in VHAP service, it must be determined that the percent 
VHAP content can be reasonably expected never to exceed 10.0 percent by 
weight. For the purposes of determining the percent VHAP content of the 
process fluid that is contained in or contacts a piece of ancillary 
equipment or compressor, Method 18 of 40 CFR part 60, appendix A, shall 
be used.
    (2) For a piece of ancillary equipment and compressors to be 
considered in wet gas service, it must be determined that it contains 
or contacts the field gas before the extraction of natural gas liquids.
    (b) Determination of glycol dehydration unit flowrate or benzene 
emissions. The procedures of this paragraph shall be used by an owner 
or operator to determine glycol dehydration unit natural gas flowrate 
or benzene emissions to meet the criteria for an exemption from control 
requirements under Sec. 63.764(e)(1).
    (1) The determination of actual flowrate 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 natural gas flowrate to the glycol 
dehydration unit with an accuracy of plus or minus 2 percent or better. 
The owner or operator shall convert annual natural gas flowrate to a 
daily average by dividing the annual flowrate by the number of days per 
year the glycol dehydration unit processed natural gas.
    (ii) The owner or operator shall document, to the Administrator's 
satisfaction, that the actual annual average natural gas flowrate to 
the glycol dehydration unit is less than 85 thousand standard cubic 
meters per day.
    (2) The determination of actual average 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. Emissions shall be 
determined either uncontrolled, or with federally enforceable controls 
in place.
    (i) The owner or operator shall determine actual average benzene 
emissions using the model GRI-GLYCalcTM, Version 3.0 or 
higher, and the procedures presented in the associated GRI-
GLYCalcTM Technical Reference Manual. Inputs to the model 
shall be representative of actual operating conditions of the glycol 
dehydration unit and may be

[[Page 32636]]

determined using the procedures documented in the Gas Research 
Institute (GRI) report entitled ``Atmospheric Rich/Lean Method for 
Determining Glycol Dehydrator Emissions'' (GRI-95/0368.1); 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 converted to megagrams 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) An owner or operator may choose to adjust or not adjust the 
detection instrument readings to account for the background organic 
concentration level. If an owner or operator chooses to adjust the 
instrument readings for the background level, the background level 
value must be determined according to the procedures in Method 21 of 40 
CFR part 60, appendix A.
    (6)(i) Except as provided in paragraph (c)(6)(i) of this section, 
the detection instrument shall meet the performance criteria of Method 
21 of 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 process fluid not each individual volatile organic 
compound in the stream. For process streams that contain nitrogen, air, 
or other inerts which are not organic hazardous air pollutants or 
volatile organic compounds, the average stream response factor shall be 
calculated on an inert-free basis.
    (ii) If no instrument is available at the facility that will meet 
the performance criteria specified in paragraph (c)(6)(i) of this 
section, the instrument readings may be adjusted by multiplying by the 
average response factor of the process fluid, calculated on an inert-
free basis as described in paragraph (c)(6)(i) of this section.
    (7) An owner or operator must determine if a potential leak 
interface operates with no detectable emissions using the applicable 
procedure specified in paragraph (c)(7)(i) or (c)(7)(ii) of this 
section.
    (i) If an owner or operator chooses not to adjust the detection 
instrument readings for the background organic concentration level, 
then the maximum organic concentration value measured by the detection 
instrument is compared directly to the applicable value for the 
potential leak interface as specified in paragraph (c)(8) of this 
section.
    (ii) If an owner or operator chooses to adjust the detection 
instrument readings for the background organic concentration level, the 
value of the arithmetic difference between the maximum organic 
concentration value measured by the instrument and the background 
organic concentration value as determined in paragraph (c)(5) of this 
section is compared with the applicable value for the potential leak 
interface as specified in paragraph (c)(8) of this section.
    (8) A potential leak interface is determined to operate with no 
detectable organic emissions if the organic concentration value 
determined in paragraph (c)(7) of this section, is less than 500 parts 
per million by volume.
    (d) [Reserved]
    (e) Control device performance test procedures. This paragraph 
applies to the performance testing of control devices. The owners or 
operators shall demonstrate that a control device achieves the 
performance requirements of Sec. 63.771(d)(1) or (e)(3)(ii) using 
either a performance test as specified in paragraph (e)(3) of this 
section or a design analysis as specified in paragraph (e)(4) of this 
section. The owner or operator may elect to use the alternative 
procedures in paragraph (e)(5) of this section for performance testing 
of a condenser used to control emissions from a glycol dehydration unit 
process vent.
    (1) The following control devices are exempt from the requirements 
to conduct performance tests and design analyses under this section:
    (i) A flare that is designed and operated in accordance with 
Sec. 63.11(b);
    (ii) A boiler or process heater with a design heat input capacity 
of 44 megawatts or greater;
    (iii) A boiler or process heater into which the vent stream is 
introduced with the primary fuel or is used as the primary fuel;
    (iv) 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;
    (v) A hazardous waste incinerator for which the owner or operator 
has been issued a final permit under 40 CFR part 270 and complies with 
the requirements of 40 CFR part 264, subpart O; or has certified 
compliance with the interim status requirements of 40 CFR part 265, 
subpart O.
    (vi) A control device for which a performance test was conducted 
for determining compliance with a regulation promulgated by the EPA and 
the test was conducted using the same methods specified in this section 
and either no process changes have been made since the test, or the 
owner or operator can demonstrate that the results of the performance 
test, with or without adjustments, reliably demonstrate compliance 
despite process changes.
    (2) An owner or operator shall design and operate each flare in 
accordance with the requirements specified in Sec. 63.11(b) and in 
paragraphs (e)(2)(i) and (e)(2)(ii) of this section.
    (i) The compliance determination shall be conducted using Method 22 
of 40 CFR part 60, appendix A, to determine visible emissions.
    (ii) An owner or operator is not required to conduct a performance 
test to determine percent emission reduction or outlet organic HAP or 
TOC concentration when a flare is used.
    (3) For a performance test conducted to demonstrate that a control 
device meets the requirements of Sec. 63.771(d)(1) or (e)(3)(ii), the 
owner or operator shall use the test methods and procedures specified 
in paragraphs (e)(3)(i) through (e)(3)(iv) of this section. The 
performance test shall be conducted according to the schedule specified 
in Sec. 63.7(a)(2) and the results of the performance test shall be 
submitted in the Notification of Compliance Status Report as required 
in Sec. 63.775(d)(1)(ii.
    (i) Method 1 or 1A, 40 CFR part 60, appendix A, as appropriate, 
shall be used for selection of the sampling sites in paragraphs 
(e)(3)(i)(A) and (B) of this section. Any references to particulate

[[Page 32637]]

mentioned in Methods 1 and 1A do not apply to this section.
    (A) To determine compliance with the control device percent 
reduction requirement specified in Sec. 63.771(d)(1)(i)(A), (d)(1)(ii) 
or (e)(3)(ii), sampling sites shall be located at the inlet of the 
first control device, and at the outlet of the final control device.
    (B) 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 combustion device.
    (ii) The gas volumetric flowrate shall be determined using Method 
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
    (iii) To determine compliance with the control device percent 
reduction performance requirement in 
Sec. 63.771(d)(1)(i)(A),(d)(1)(ii), and (e)(3)(ii), the owner or 
operator shall use either Method 18, 40 CFR part 60, appendix A or 
Method 25A, 40 CFR part 60, appendix A; alternatively, any other method 
or data that have 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:
    (A) 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.
    (B) The mass rate of either TOC (minus methane and ethane) or total 
HAP (Ei, Eo) shall be computed.
    (1) The following equations shall be used:
    [GRAPHIC] [TIFF OMITTED] TR17JN99.000
    
    [GRAPHIC] [TIFF OMITTED] TR17JN99.001
    
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 = Flowrate of gas stream at the inlet and 
outlet of the control device, respectively, dry standard cubic meter 
per minute.
    K2 = Constant, 2.494x10-6 (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.
    (2) When the TOC mass rate is calculated, all organic compounds 
(minus methane and ethane) measured by Method 18, 40 CFR part 60, 
appendix A, or Method 25A, 40 CFR part 60, appendix A, shall be summed 
using the equations in paragraph (e)(3)(iii)(B)(1) of this section.
    (3) When the total HAP mass rate is calculated, only HAP chemicals 
listed in Table 1 of this subpart shall be summed using the equations 
in paragraph (e)(3)(iii)(B)(1) of this section.
    (C) The percent reduction in TOC (minus methane and ethane) or 
total HAP shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR17JN99.002

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)(iii)(B) 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)(iii)(B) of this section, kilograms TOC per hour or kilograms HAP 
per hour.

    (D) 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.
    (iv) 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 either Method 18, 40 CFR part 60, appendix 
A, or Method 25A, 40 CFR part 60, appendix A, to measure either TOC 
(minus methane and ethane) or total HAP. Alternatively, any other 
method or data that have been validated according to Method 301 of 
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:
    (A) 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.
    (B) The TOC concentration or total HAP concentration shall be 
calculated according to paragraph (e)(3)(iv)(B)(1) or (e)(3)(iv)(B)(2) 
of this section.
    (1) 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] TR17JN99.003

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.

    (2) The total HAP concentration shall be computed according to the 
equation in paragraph (e)(3)(iv)(B)(1) of this section, except that 
only HAP chemicals listed in Table 1 of this subpart shall be summed.
    (C) The TOC concentration or total HAP concentration shall be 
corrected to 3 percent oxygen as follows:
    (1) The emission rate correction factor for 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.
    (2) The TOC or HAP concentration shall be corrected for percent 
oxygen by using the following equation:
[GRAPHIC] [TIFF OMITTED] TR17JN99.004


[[Page 32638]]


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.

    (4) For a design analysis conducted to meet the requirements of 
Sec. 63.771(d)(1) or (e)(3)(ii), the owner or operator shall meet the 
requirements specified in paragraphs (e)(4)(i) and (e)(4)(ii) of this 
section. Documentation of the design analysis shall be submitted as a 
part of the Notification of Compliance Status Report as required in 
Sec. 63.775(d)(1)(i).
    (i) 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 (e)(4)(i)(A) 
through (F) of this section.
    (A) For a thermal vapor incinerator, the design analysis shall 
include the vent stream composition, constituent concentrations, and 
flowrate and shall establish the design minimum and average 
temperatures in the combustion zone and the combustion zone residence 
time.
    (B) For a catalytic vapor incinerator, the design analysis shall 
include the vent stream composition, constituent concentrations, and 
flowrate and shall establish the design minimum and average 
temperatures across the catalyst bed inlet and outlet, and the design 
service life of the catalyst.
    (C) For a boiler or process heater, the design analysis shall 
include the vent stream composition, constituent concentrations, and 
flowrate; 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.
    (D) For a condenser, the design analysis shall include the vent 
stream composition, constituent concentrations, flowrate, 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. As an alternative 
to the design analysis, an owner or operator may elect to use the 
procedures specified in paragraph (e)(5) of this section.
    (E) For a regenerable carbon adsorption system, the design analysis 
shall include the vent stream composition, constituent concentrations, 
flowrate, 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 the 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.
    (F) For a nonregenerable carbon adsorption system, such as a carbon 
canister, the design analysis shall include the vent stream 
composition, constituent concentrations, flowrate, relative humidity, 
and temperature, and shall establish the design exhaust vent stream 
organic compound concentration level, capacity of the carbon bed, type 
and working capacity of activated carbon used for the 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.
    (ii) 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 (e)(3) of this section. The Administrator 
may choose to have an authorized representative observe the performance 
test.
    (5) As an alternative to the procedures in paragraphs (e)(3) and 
(e)(4)(i)(D) of this section, an owner or operator may elect to use the 
procedures documented in the GRI report entitled, ``Atmospheric Rich/
Lean Method for Determining Glycol Dehydrator Emissions'' (GRI-95/
0368.1) as inputs for the model GRI-GLYCalcTM, Version 3.0 
or higher, to determine condenser performance.
    (f) Compliance demonstration for control device performance 
requirements. This paragraph applies to the demonstration of compliance 
with the control device performance requirements specified in 
Secs. 63.771(d)(1)(ii) and 63.765(c)(2). Compliance shall be 
demonstrated using the requirements in paragraphs (f)(1) through (f)(3) 
of this section. As an alternative, an owner or operator that installs 
a condenser as the control device to achieve the requirements specified 
in Sec. 63.771(d)(1)(ii) or Sec. 63.765(c)(2), may demonstrate 
compliance according to paragraph (g) of this section. An owner or 
operator may switch between compliance with paragraph (f) of this 
section and compliance with paragraph (g) of this section only after at 
least 1 year of operation in compliance with the selected approach. 
Notification of such a change in the compliance method shall be 
reported in the next Periodic Report, as required in Sec. 63.775(e), 
following the change.
    (1) The owner or operator shall establish a site specific maximum 
or minimum monitoring parameter value (as appropriate) according to the 
requirements of Sec. 63.773(d)(5)(i).
    (2) The owner or operator shall calculate the daily average of the 
applicable monitored parameter in accordance with Sec. 63.773(d)(4).
    (3) Compliance with the operating parameter limit is achieved when 
the daily average of the monitoring parameter value calculated under 
paragraph (f)(2) of this section is either equal to or greater than the 
minimum or equal to or less than the maximum monitoring value 
established under paragraph (f)(1) of this section.
    (g) Compliance demonstration with percent reduction performance 
requirements--condensers. This paragraph applies to the demonstration 
of compliance with the performance requirements specified in 
Sec. 63.771(d)(1)(ii) or Sec. 63.765(c)(2) for condensers. Compliance 
shall be demonstrated using the procedures in paragraphs (g)(1) through 
(g)(3) of this section.
    (1) The owner or operator shall establish a site-specific condenser 
performance curve according to Sec. 63.773(d)(5)(ii).
    (2) Compliance with the percent reduction requirement in 
Sec. 63.771(d)(1)(ii) or Sec. 63.765(c)(2) shall be demonstrated by the 
procedures in paragraphs (g)(2)(i) through (g)(2)(iii) of this section.
    (i) The owner or operator must calculate the daily average 
condenser outlet temperature in accordance with Sec. 63.773(d)(4).
    (ii) The owner or operator shall determine the condenser efficiency 
for the current operating day using the daily average condenser outlet 
temperature calculated under paragraph (g)(2)(i) of this section and 
the condenser performance curve established under paragraph (g)(1) of 
this section.
    (iii) Except as provided in paragraphs (g)(2)(iii) (A) and (B) of 
this section, at the end of each operating day, the

[[Page 32639]]

owner or operator shall calculate the 365-day average HAP emission 
reduction from the condenser efficiencies determined in paragraph 
(g)(2)(ii) of this section for the preceding 365 operating days. If the 
owner or operator uses a combination of process modifications and a 
condenser in accordance with the requirements of Sec. 63.765(c)(2), the 
365-day average HAP emission reduction shall be calculated using the 
emission reduction achieved through process modifications and the 
condenser efficiency determined in paragraph (g)(2)(ii) of this 
section, both for the previous 365 operating days.
    (A) After the compliance dates specified in Sec. 63.760(f), an 
owner or operator with less than 120 days of data for determining 
average HAP emission reduction, shall calculate the average HAP 
emission reduction for the first 120 days of operation after the 
compliance dates. Compliance with the performance requirements is 
achieved if the 120-day average HAP emission reduction is equal to or 
greater than 90.0 percent.
    (B) After 120 days and no more than 364 days of operation after the 
compliance dates specified in Sec. 63.760(f), the owner or operator 
shall calculate the average HAP emission reduction as the HAP emission 
reduction averaged over the number of days between the current day and 
the applicable compliance date. Compliance with the performance 
requirements is achieved if the average HAP emission reduction is equal 
to or greater than 90.0 percent.
    (3) If the owner or operator has data for 365 days or more of 
operation, compliance is achieved with the emission limitation 
specified in Sec. 63.771(d)(1)(ii) or Sec. 63.765(c)(2) if the average 
HAP emission reduction calculated in paragraph (g)(2)(iii) of this 
section is equal to or greater than 95.0 percent.


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) [Reserved]
    (c) Cover and closed-vent system inspection and monitoring 
requirements. (1) For each closed-vent system or cover required to 
comply with this section, the owner or operator shall comply with the 
requirements of paragraphs (c) (2) through (7) of this section.
    (2) Except as provided in paragraphs (c) (5) and (6) of this 
section, each closed-vent system shall be inspected according to the 
procedures and schedule specified in paragraphs (c)(2) (i) and (ii) of 
this section, and each cover shall be inspected according to the 
procedures and schedule specified in paragraph (c)(2)(iii) of this 
section.
    (i) For each closed-vent system joints, seams, or other connections 
that are permanently or semi-permanently sealed (e.g., a welded joint 
between two sections of hard piping or a bolted and gasketed ducting 
flange), the owner or operator shall:
    (A) Conduct an initial inspection according to the procedures 
specified in Sec. 63.772(c) to demonstrate that the closed-vent system 
operates with no detectable emissions.
    (B) Conduct annual visual inspections for defects that could result 
in air emissions. Defects include, but are not limited to, visible 
cracks, holes, or gaps in piping; loose connections; or broken or 
missing caps or other closure devices. The owner or operator shall 
monitor a component or connection using the procedures in 
Sec. 63.772(c) to demonstrate that it operates with no detectable 
emissions following any time the component is repaired or replaced or 
the connection is unsealed.
    (ii) For closed-vent system components other than those specified 
in paragraph (c)(2)(i) of this section, the owner or operator shall:
    (A) Conduct an initial inspection according to the procedures 
specified in Sec. 63.772(c) to demonstrate that the closed-vent system 
operates with no detectable emissions.
    (B) Conduct annual inspections according to the procedures 
specified in Sec. 63.772(c) to demonstrate that the components or 
connections operate with no detectable emissions.
    (C) Conduct annual visual inspections for defects that could result 
in air emissions. Defects include, but are not limited to, visible 
cracks, holes, or gaps in ductwork; loose connections; or broken or 
missing caps or other closure devices.
    (iii) For each cover, the owner or operator shall:
    (A) Conduct visual inspections for defects that could result in air 
emissions. Defects include, but are not limited to, visible cracks, 
holes, or gaps in the cover, or between the cover and the separator 
wall; broken, cracked, or otherwise damaged seals or gaskets on closure 
devices; and broken or missing hatches, access covers, caps, or other 
closure devices. In the case where the tank is buried partially or 
entirely underground, inspection is required only for those portions of 
the cover that extend to or above the ground surface, and those 
connections that are on such portions of the cover (e.g., fill ports, 
access hatches, gauge wells, etc.) and can be opened to the atmosphere.
    (B) The inspections shall be conducted initially, following the 
installation of the cover. Thereafter, the owner or operator shall 
perform the inspection at least once every calendar year, except as 
provided in paragraphs (c) (5) and (6) of this section.
    (3) In the event that a leak or defect is detected, the owner or 
operator shall repair the leak or defect as soon as practicable, except 
as provided in paragraph (c)(4) of this section.
    (i) A first attempt at repair shall be made no later than 5 
calendar days after the leak is detected.
    (ii) Repair shall be completed no later than 15 calendar days after 
the leak is detected.
    (4) Delay of repair of a closed-vent system or cover for which 
leaks or defects have been detected is allowed if the repair is 
technically infeasible without a shutdown, as defined in Sec. 63.761, 
or if the owner or operator determines that emissions resulting from 
immediate repair would be greater than the fugitive emissions likely to 
result from delay of repair. Repair of such equipment shall be complete 
by the end of the next shutdown.
    (5) Any parts of the closed-vent system or cover that are 
designated, as described in paragraphs (c)(5) (i) and (ii) of this 
section, as unsafe to inspect are exempt from the inspection 
requirements of paragraphs (c)(2)(i), (ii), and (iii) of this section 
if:
    (i) The owner or operator determines that the equipment is unsafe 
to inspect because inspecting personnel would be exposed to an imminent 
or potential danger as a consequence of complying with paragraphs 
(c)(2)(i), (ii), or (iii) of this section; and
    (ii) The owner or operator has a written plan that requires 
inspection of the equipment as frequently as practicable during safe-
to-inspect times.
    (6) Any parts of the closed-vent system or cover that are 
designated, as described in paragraphs (c)(6) (i) and (ii) of this 
section, as difficult to inspect are exempt from the inspection 
requirements of paragraphs (c)(2)(i), (ii), and (iii) of this section 
if:
    (i) The owner or operator determines that the equipment cannot be 
inspected without elevating the inspecting personnel more than 2 meters 
above a support surface; and
    (ii) The owner or operator has a written plan that requires 
inspection of the equipment at least once every 5 years.
    (7) Records shall be maintained as specified in Sec. 63.774(b)(5) 
through (8).

[[Page 32640]]

    (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 parameter 
monitoring system in accordance with the requirements of paragraphs 
(d)(3) through (9) of this section. The continuous monitoring system 
shall be designed and operated so that a determination can be made on 
whether the control device is achieving the applicable performance 
requirements of Sec. 63.771(d) or Sec. 63.771(e)(3). The continuous 
parameter monitoring system shall meet the following specifications and 
requirements:
    (i) Each continuous parameter monitoring system shall measure data 
values at least once every hour and record either:
    (A) Each measured data value; or
    (B) Each block average value for each 1-hour period or shorter 
periods calculated from all measured data values during each period. If 
values are measured more frequently than once per minute, a single 
value for each minute may be used to calculate the hourly (or shorter 
period) block average instead of all measured values.
    (ii) The monitoring system must be installed, calibrated, operated, 
and maintained in accordance with the manufacturer's specifications or 
other written procedures that provide reasonable assurance that the 
monitoring equipment is operating properly.
    (2) An owner or operator is exempt from the monitoring requirements 
specified in paragraphs (d)(3) through (9) of this section for the 
following types of control devices:
    (i) A boiler or process heater in which all vent streams are 
introduced with the primary fuel or is used as the 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.
    (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 a minimum accuracy of 2 percent of the temperature 
being monitored in  deg.C ,or 2.5  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 a minimum accuracy 
of 2 percent of the temperature being monitored in  deg.C, 
or 2.5  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 a minimum accuracy of 2 percent of the 
temperature being monitored in  deg.C, or 2.5  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 a 
minimum accuracy of 2 percent of the temperature being 
monitored in  deg.C, or 2.5  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:
    (1) A continuous parameter monitoring system to measure and record 
the average total regeneration stream mass flow or volumetric flow 
during each carbon bed regeneration cycle. The integrating regenerating 
stream flow monitoring device must have an accuracy of 10 
percent; and
    (2) A continuous parameter monitoring system to measure and record 
the average carbon bed temperature for the duration of the carbon bed 
steaming cycle and to measure the actual carbon bed temperature after 
regeneration and within 15 minutes of completing the cooling cycle. The 
temperature monitoring device shall have a minimum accuracy of 
2 percent of the temperature being monitored in  deg.C, or 
2.5  deg.C, whichever value is greater.
    (G) For a nonregenerative-type carbon adsorption system, the owner 
or operator shall monitor the design carbon replacement interval 
established using a performance test performed in accordance with 
Sec. 63.772(e)(3) or a design analysis in accordance with 
Sec. 63.772(e)(4)(i)(F) and shall be based on the total carbon working 
capacity of the control device and source operating schedule.
    (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. The monitor must meet the requirements of Performance 
Specification 8 or 9 of appendix B of 40 CFR part 60 and must be 
installed, calibrated, and maintained according to the manufacturer's 
specifications.
    (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 (5).
    (4) Using the data recorded by the monitoring system, the owner or 
operator must calculate the daily average value for each monitored 
operating parameter for each operating day. If the HAP emissions unit 
operation is continuous, the operating day is a 24-hour period. If HAP 
emissions unit operation is not continuous, the operating day is the 
total number of hours of control device operation per 24-hour period. 
Valid data points must be available for 75 percent of the operating 
hours in an operating day to compute the daily average.
    (5) For each operating parameter monitor installed in accordance 
with the requirements of paragraph (d)(3) of this section, the owner or 
operator shall comply with paragraph (d)(5)(i) of this section for all 
control devices except for condensers, and when condensers are 
installed, the owner or operator shall also comply with paragraph 
(d)(5)(ii) of this section.
    (i) 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(d)(1) or Sec. 63.771(e)(3)(ii). 
Each minimum or maximum operating parameter value shall be established 
as follows:

[[Page 32641]]

    (A) If the owner or operator conducts performance tests in 
accordance with the requirements of Sec. 63.772(e)(3) to demonstrate 
that the control device achieves the applicable performance 
requirements specified in Sec. 63.771(d)(1) or Sec. 63.771(e)(3)(ii), 
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 or control device manufacturer recommendations or a 
combination of both.
    (B) If the owner or operator uses a control device design analysis 
in accordance with the requirements of Sec. 63.772(e)(4) to demonstrate 
that the control device achieves the applicable performance 
requirements specified in Sec. 63.771(d)(1) or (e)(3)(ii), then the 
minimum operating parameter value or the maximum operating parameter 
value shall be established based on the control device design analysis 
and may be supplemented by the control device manufacturer's 
recommendations.
    (ii) The owner or operator shall establish a condenser performance 
curve showing the relationship between condenser outlet temperature and 
condenser control efficiency. The curve shall be established as 
follows:
    (A) If the owner or operator conducts a performance test in 
accordance with the requirements of Sec. 63.772(e)(3) to demonstrate 
that the condenser achieves the applicable performance requirements in 
Sec. 63.771(d)(1) or (e)(3)(ii), then the condenser performance curve 
shall be based on values measured during the performance test and 
supplemented as necessary by control device design analysis, or control 
device manufacturer's recommendations, or a combination or both.
    (B) If the owner or operator uses a control device design analysis 
in accordance with the requirements of Sec. 63.772(e)(4)(i)(D) to 
demonstrate that the condenser achieves the applicable performance 
requirements specified in Sec. 63.771(d)(1) or (e)(3)(ii), then the 
condenser performance curve shall be based on the condenser design 
analysis and may be supplemented by the control device manufacturer's 
recommendations.
    (C) As an alternative to paragraphs (d)(5)(ii)(A) and (B) of this 
section, the owner or operator may elect to use the procedures 
documented in the GRI report entitled, ``Atmospheric Rich/Lean Method 
for Determining Glycol Dehydrator Emissions'' (GRI-95/0368.1) as inputs 
for the model GRI-GLYCalcTM, Version 3.0 or higher, to 
generate a condenser performance curve.
    (6) An excursion for a given control device is determined to have 
occurred when the monitoring data or lack of monitoring data result in 
any one of the criteria specified in paragraphs (d)(6)(i) through 
(d)(6)(v) of this section being met. When multiple operating parameters 
are monitored for the same control device and during the same operating 
day and more than one of these operating parameters meets an excursion 
criterion specified in paragraphs (d)(6)(i) through (d)(6)(v) of this 
section, then a single excursion is determined to have occurred for the 
control device for that operating day.
    (i) An excursion occurs when the daily average value of a monitored 
operating parameter is less than the minimum operating parameter limit 
(or, if applicable, greater than the maximum operating parameter limit) 
established for the operating parameter in accordance with the 
requirements of paragraph (d)(5)(i) of this section.
    (ii) An excursion occurs when the 365-day average condenser 
efficiency calculated according to the requirements specified in 
Sec. 63.772(g)(2)(iii) is less than 95.0 percent.
    (iii) If an owner or operator has less than 365 days of data, an 
excursion occurs when the average condenser efficiency calculated 
according to the procedures specified in Sec. 63.772(g)(2)(iii)(A) or 
(B) is less than 90.0 percent.
    (iv) An excursion occurs when the monitoring data are not available 
for at least 75 percent of the operating hours.
    (v) 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, an excursion occurs when:
    (A) For each bypass line subject to Sec. 63.771(c)(3)(i)(A) the 
flow indicator indicates that flow has been detected and that the 
stream has been diverted away from the control device to the 
atmosphere.
    (B) For each bypass line subject to Sec. 63.771(c)(3)(i)(B), if the 
seal or closure mechanism has been broken, the bypass line valve 
position has changed, the key for the lock-and-key type lock has been 
checked out, or the car-seal has broken.
    (7) For each excursion, except as provided for in paragraph (d)(8) 
of this section, the owner or operator shall be deemed to have failed 
to have applied control in a manner that achieves the required 
operating parameter limits. Failure to achieve the required operating 
parameter limits is a violation of this standard.
    (8) An excursion is not a violation of the operating parameter 
limit as specified in paragraphs (d)(8)(i) and (d)(8)(ii) of this 
section.
    (i) An excursion does not count toward the number of excused 
excursions allowed under paragraph (d)(8)(ii) of this section when the 
excursion occurs during any one of the following periods:
    (A) During a period of startup, shutdown, or malfunction when the 
affected facility is operated during such period in accordance with the 
facility's startup, shutdown, and malfunction plan; or
    (B) During periods of non-operation of the unit or the process that 
is vented to the control device (resulting in cessation of HAP 
emissions to which the monitoring applies).
    (ii) For each control device, or combinations of control devices 
installed on the same HAP emissions unit, one excused excursion is 
allowed per semiannual period for any reason. The initial semiannual 
period is the 6-month reporting period addressed by the first Periodic 
Report submitted by the owner or operator in accordance with 
Sec. 63.775(e) of this subpart.
    (9) Nothing in paragraphs (d)(1) through (d)(8) of this section 
shall be construed to allow or excuse a monitoring parameter excursion 
caused by any activity that violates other applicable provisions of 
this subpart.


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 facility subject to this subpart shall 
maintain the records specified in paragraphs (b)(1) through (b)(11) of 
this section:
    (1) The owner or operator of an affected source subject to the 
provisions of this subpart shall maintain files of all information 
(including all reports and notifications) required by this subpart. The 
files shall be retained for at least 5 years following the date of each 
occurrence, measurement, maintenance, corrective action, report or 
period.
    (i) All applicable records shall be maintained in such a manner 
that they can be readily accessed.
    (ii) The most recent 12 months of records shall be retained on site 
or shall be accessible from a central location by

[[Page 32642]]

computer or other means that provides access within 2 hours after a 
request.
    (iii) The remaining 4 years of records may be retained offsite.
    (iv) Records may be maintained in hard copy or computer-readable 
form including, but not limited to, on paper, microfilm, computer, 
floppy disk, magnetic tape, or microfiche.
    (2) Records specified in Sec. 63.10(b)(2);
    (3) 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). Notwithstanding the requirements of Sec. 63.10(c), 
monitoring data recorded during periods identified in paragraphs 
(b)(3)(i) through (b)(3)(iv) of this section shall not be included in 
any average or percent leak rate computed under this subpart. Records 
shall be kept of the times and durations of all such periods and any 
other periods during process or control device operation when monitors 
are not operating.
    (i) Monitoring system breakdowns, repairs, calibration checks, and 
zero (low-level) and high-level adjustments;
    (ii) Startups, shutdowns, or malfunctions events. During startups, 
shutdowns, or malfunction events, the owner or operator shall maintain 
records indicating whether or not the startup, shutdown or malfunction 
plan required under Sec. 63.762(d), was followed.
    (iii) Periods of non-operation resulting in cessation of the 
emissions to which the monitoring applies; and
    (iv) Excursions due to invalid data as defined in 
Sec. 63.773(d)(6)(iv).
    (4) Each owner or operator using a control device to comply with 
Sec. 63.764 of this subpart shall keep the following records up-to-date 
and readily accessible:
    (i) Continuous records of the equipment operating parameters 
specified to be monitored under Sec. 63.773(d) of this subpart or 
specified by the Administrator in accordance with 
Sec. 63.773(d)(3)(iii) of this subpart. For flares, the hourly records 
and records of pilot flame outages specified in Sec. 63.773(d)(3)(i)(C) 
of this subpart shall be maintained in place of continuous records.
    (ii) Records of the daily average value of each continuously 
monitored parameter for each operating day determined according to the 
procedures specified in Sec. 63.773(d)(4) of this subpart, except as 
specified in paragraphs (b)(4)(ii)(A) and (B) of this section.
    (A) For flares, records of the times and duration of all periods 
during which all pilot flames are absent shall be kept rather than 
daily averages.
    (B) For condensers installed to comply with Sec. 63.765, records of 
the annual 365-day rolling average condenser efficiency determined 
under Sec. 63.772(g) shall be kept in addition to the daily averages.
    (iii) Hourly records of whether the flow indicator specified under 
Sec. 63.771(c)(3)(i)(A) was operating and whether flow was detected at 
any time during the hour, as well as records of the times and durations 
of all periods when the vent stream is diverted from the control device 
or the monitor is not operating.
    (iv) Where a seal or closure mechanism is used to comply with 
Sec. 63.771(c)(3)(i)(B), hourly records of flow are not required. In 
such cases, the owner or operator shall record that the monthly visual 
inspection of the seals or closure mechanism has been done, and shall 
record the duration of all periods when the seal mechanism is broken, 
the bypass line valve position has changed, or the key for a lock-and-
key type lock has been checked out, and records of any car-seal that 
has broken.
    (5) Records identifying all parts of the cover or closed-vent 
system that are designated as unsafe to inspect in accordance with 
Sec. 63.773(c)(5), an explanation of why the equipment is unsafe to 
inspect, and the plan for inspecting the equipment.
    (6) Records identifying all parts of the cover or closed-vent 
system that are designated as difficult to inspect in accordance with 
Sec. 63.773(c)(6), an explanation of why the equipment is difficult to 
inspect, and the plan for inspecting the equipment.
    (7) For each inspection conducted in accordance with 
Sec. 63.773(c), during which a leak or defect is detected, a record of 
the information specified in paragraphs (b)(7)(i) through (b)(7)(viii) 
of this section.
    (i) The instrument identification numbers, operator name or 
initials, and identification of the equipment.
    (ii) The date the leak or defect was detected and the date of the 
first attempt to repair the leak or defect.
    (iii) Maximum instrument reading measured by the method specified 
in Sec. 63.772(c) after the leak or defect is successfully repaired or 
determined to be nonrepairable.
    (iv) ``Repair delayed'' and the reason for the delay if a leak or 
defect is not repaired within 15 calendar days after discovery of the 
leak or defect.
    (v) The name, initials, or other form of identification of the 
owner or operator (or designee) whose decision it was that repair could 
not be effected without a shutdown.
    (vi) The expected date of successful repair of the leak or defect 
if a leak or defect is not repaired within 15 calendar days.
    (vii) Dates of shutdowns that occur while the equipment is 
unrepaired.
    (viii) The date of successful repair of the leak or defect.
    (8) For each inspection conducted in accordance with Sec. 63.773(c) 
during which no leaks or defects are detected, a record that the 
inspection was performed, the date of the inspection, and a statement 
that no leaks were detected.
    (9) Records identifying ancillary equipment and compressors that 
are subject to and controlled under the provisions of 40 CFR part 60, 
subpart KKK; 40 CFR part 61, subpart V; or 40 CFR part 63, subpart H.
    (10) Records of glycol dehydration unit baseline operations 
calculated as required under Sec. 63.771(e)(1).
    (11) Records required in Sec. 63.771(e)(3)(i) documenting that the 
facility continues to operate under the conditions specified in 
Sec. 63.771(e)(2).
    (c) An owner or operator that elects to comply with the benzene 
emission limit specified in Sec. 63.765(b)(1)(ii) shall document, to 
the Administrator's satisfaction, the following items:
    (1) The method used for achieving compliance and the basis for 
using this compliance method; and
    (2) The method used for demonstrating compliance with 0.90 
megagrams per year of benzene.
    (3) Any information necessary to demonstrate compliance as required 
in the methods specified in paragraphs (c)(1) and (c)(2) of this 
section.
    (d) (1) An owner or operator that is exempt from control 
requirements under Sec. 63.764(e)(1) shall maintain the records 
specified in paragraph (d)(1)(i) or (d)(1)(ii) of this section, as 
appropriate, for each glycol dehydration unit that is not controlled 
according to the requirements of Sec. 63.764(c)(1)(i).
    (i) The actual annual average natural gas throughput (in terms of 
natural gas flowrate to the glycol dehydration unit per day) as 
determined in accordance with Sec. 63.772(b)(1), or
    (ii) The actual average benzene emissions (in terms of benzene 
emissions per year) as determined in accordance with Sec. 63.772(b)(2).
    (2) An owner or operator that is exempt from the control 
requirements under Sec. 63.764(e)(2) of this subpart shall maintain the 
following records:
    (i) Information and data used to demonstrate that a piece of 
equipment is not in VHAP service or not in wet gas service shall be 
recorded in a log that is kept in a readily accessible location.

[[Page 32643]]

    (ii) Identification and location of equipment, located at a natural 
gas processing plant subject to this subpart, that is in VHAP service 
less than 300 hours per year.
    (e) Record the following when using a flare to comply with 
Sec. 63.771(d):
    (1) Flare design (i.e., steam-assisted, air-assisted, or non-
assisted);
    (2) All visible emission readings, heat content determinations, 
flowrate measurements, and exit velocity determinations made during the 
compliance determination required by Sec. 63.772(e)(2); and
    (3) All periods during the compliance determination when the pilot 
flame is absent.


Sec. 63.775  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 sources subject 
to this subpart are listed in Table 2 of this subpart.
    (b) Each owner or operator of a major source subject to this 
subpart shall submit the information listed in paragraphs (b)(1) 
through (b)(6) of this section, except as provided in paragraphs (b)(7) 
and (b)(8) of this section.
    (1) The initial notifications required for existing affected 
sources under Sec. 63.9(b)(2) shall be submitted by 1 year after an 
affected source becomes subject to the provisions of this subpart or by 
June 17, 2000, whichever is later. Affected sources that are major 
sources on or before June 17, 2000 and plan to be area sources by June 
17, 2002 shall include in this notification a brief, nonbinding 
description of a schedule for the action(s) that are planned to achieve 
area source status.
    (2) The date of the performance evaluation as specified in 
Sec. 63.8(e)(2), required only if the owner or operator is required by 
the Administrator to conduct a performance evaluation for a continuous 
monitoring system. A separate notification of the performance 
evaluation is not required if it is included in the initial 
notification submitted in accordance with paragraph (b)(1) of this 
section.
    (3) The planned date of a performance test at least 60 days before 
the test in accordance with Sec. 63.7(b). Unless requested by the 
Administrator, a site-specific test plan is not required by this 
subpart. If requested by the Administrator, the owner or operator must 
also submit the site-specific test plan required by Sec. 63.7(c) with 
the notification of the performance test. A separate notification of 
the performance test is not required if it is included in the initial 
notification submitted in accordance with paragraph (b)(1) of this 
section.
    (4) A Notification of Compliance Status report as described in 
paragraph (d) of this section;
    (5) Periodic Reports as described in paragraph (e) of this section; 
and
    (6) Startup, shutdown, and malfunction reports specified in 
Sec. 63.10(d)(5) shall be submitted as required. Separate startup, 
shutdown, and malfunction reports as described in Sec. 63.10(d)(5) are 
not required if the information is included in the Periodic Report 
specified in paragraph (e) of this section.
    (7) Each owner or operator of a glycol dehydration unit subject to 
this subpart that is exempt from 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, for that 
unit.
    (8) Each owner or operator of ancillary equipment and compressors 
subject to this subpart that are exempt from the control requirements 
for equipment leaks in Sec. 63.769, are exempt from all reporting 
requirements for major sources in this subpart, for that equipment.
    (c) [Reserved]
    (d) Each owner or operator of a source subject to this subpart 
shall submit a Notification of Compliance Status Report as required 
under Sec. 63.9(h) within 180 days after the compliance date specified 
in Sec. 63.760(f). In addition to the information required under 
Sec. 63.9(h), the Notification of Compliance Status Report shall 
include the information specified in paragraphs (d)(1) through (d)(11) 
of this section. This information may be submitted in an operating 
permit application, in an amendment to an operating permit application, 
in a separate submittal, or in any combination of the three. If all of 
the information required under this paragraph has been submitted at any 
time prior to 180 days after the applicable compliance dates specified 
in Sec. 63.760(f), a separate Notification of Compliance Status Report 
is not required. If an owner or operator submits the information 
specified in paragraphs (d)(1) through (d)(11) of this section at 
different times, and/or different submittals, later submittals may 
refer to earlier submittals instead of duplicating and resubmitting the 
previously submitted information.
    (1) If a closed-vent system and a control device other than a flare 
are used to comply with Sec. 63.764, the owner or operator shall 
submit:
    (i) The design analysis documentation specified in 
Sec. 63.772(e)(4) of this subpart, if the owner or operator elects to 
prepare a design analysis; or
    (ii) If the owner or operator elects to conduct a performance test, 
the performance test results including the information specified in 
paragraphs (d)(1)(ii)(A) and (B) of this section. Results of a 
performance test conducted prior to the compliance date of this subpart 
can be used provided that the test was conducted using the methods 
specified in Sec. 63.772(e)(3) and that the test conditions are 
representative of current operating conditions.
    (A) The percent reduction of HAP or TOC, or the outlet 
concentration of HAP or TOC (parts per million by volume on a dry 
basis), determined as specified in Sec. 63.772(e)(3) of this subpart; 
and
    (B) The value of the monitored parameters specified in 
Sec. 63.773(d) of this subpart, or a site-specific parameter approved 
by the permitting agency, averaged over the full period of the 
performance test.
    (2) If a closed-vent system and a flare are used to comply with 
Sec. 63.764, the owner or operator shall submit performance test 
results including the information in paragraphs (d)(2) (i) and (ii) of 
this section.
    (i) All visible emission readings, heat content determinations, 
flowrate measurements, and exit velocity determinations made during the 
compliance determination required by Sec. 63.772(e)(2) of this subpart, 
and
    (ii) A statement of whether a flame was present at the pilot light 
over the full period of the compliance determination.
    (3) For each owner or operator subject to the provisions specified 
in Sec. 63.769, the owner or operator shall submit the information 
required by Sec. 61.247(a), except that the initial report required in 
Sec. 61.247(a) shall be submitted as a part of the Notification of 
Compliance Status Report required in paragraph (d) of this section. The 
owner or operator shall also submit the information specified in 
paragraphs (d)(3) (i) and (ii) of this section.
    (i) The number of each equipment (e.g., valves, pumps, etc.) 
excluding equipment in vacuum service, and
    (ii) Any change in the information submitted in this paragraph 
shall be provided to the Administrator as a part of subsequent Periodic 
Reports described in paragraph (e)(2)(iv) of this section.
    (4) The owner or operator shall submit one complete test report for 
each test method used for a particular source.
    (i) For additional tests performed using the same test method, the 
results

[[Page 32644]]

specified in paragraph (d)(1)(ii) of this section shall be submitted, 
but a complete test report is not required.
    (ii) A complete test report shall include a sampling site 
description, description of sampling and analysis procedures and any 
modifications to standard procedures, quality assurance procedures, 
record of operating conditions during the test, record of preparation 
of standards, record of calibrations, raw data sheets for field 
sampling, raw data sheets for field and laboratory analyses, 
documentation of calculations, and any other information required by 
the test method.
    (5) For each control device other than a flare used to meet the 
requirements of Sec. 63.764, the owner or operator shall submit the 
information specified in paragraphs (d)(5) (i) through (iii) of this 
section 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) or (e)(3)(ii).
    (ii) An explanation of the rationale for why the owner or operator 
selected each of the operating parameter values established in 
Sec. 63.773(d)(5). 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) or 
Sec. 63.771(e)(3)(ii).
    (iii) A definition of the source's operating day for purposes of 
determining daily average values of monitored parameters. The 
definition shall specify the times at which an operating day begins and 
ends.
    (6) Results of any continuous monitoring system performance 
evaluations shall be included in the Notification of Compliance Status 
Report.
    (7) After a title V permit has been issued to the owner or operator 
of an affected source, the owner or operator of such source shall 
comply with all requirements for compliance status reports contained in 
the source's title V permit, including reports required under this 
subpart. After a title V permit has been issued to the owner or 
operator of an affected source, and each time a notification of 
compliance status is required under this subpart, the owner or operator 
of such source shall submit the notification of compliance status to 
the appropriate permitting authority following completion of the 
relevant compliance demonstration activity specified in this subpart.
    (8) The owner or operator that elects to comply with the 
requirements of Sec. 63.765(b)(1)(ii) shall submit the records required 
under Sec. 63.774(c).
    (9) The owner or operator shall submit an analysis demonstrating 
whether an affected source is a major source using the maximum 
throughput calculated according to Sec. 63.760(a)(1).
    (10) The owner or operator shall submit a statement as to whether 
the source has complied with the requirements of this subpart.
    (11) The owner or operator shall submit the analysis prepared under 
Sec. 63.771(e)(2) to demonstrate the conditions by which the facility 
will be operated to achieve an overall HAP emission reduction of 95.0 
percent through process modifications or a combination of process 
modifications and one or more control devices.
    (e) Periodic Reports. An owner or operator shall prepare Periodic 
Reports in accordance with paragraphs (e) (1) and (2) of this section 
and submit them to the Administrator.
    (1) An owner or operator shall submit Periodic Reports 
semiannually, beginning 60 operating days after the end of the 
applicable reporting period. The first report shall be submitted no 
later than 240 days after the date the Notification of Compliance 
Status Report is due and shall cover the 6-month period beginning on 
the date the Notification of Compliance Status Report is due.
    (2) The owner or operator shall include the information specified 
in paragraphs (e)(2)(i) through (ix) of this section, as applicable.
    (i) The information required under Sec. 63.10(e)(3). For the 
purposes of this subpart and the information required under 
Sec. 63.10(e)(3), excursions (as defined in Sec. 63.773(d)(6)) shall be 
considered excess emissions.
    (ii) A description of all excursions as defined in 
Sec. 63.773(d)(6) of this subpart that have occurred during the 6-month 
reporting period.
    (A) For each excursion caused when the daily average value of a 
monitored operating parameter is less than the minimum operating 
parameter limit (or, if applicable, greater than the maximum operating 
parameter limit), as specified in Sec. 63.773(d)(6)(i), the report must 
include the daily average values of the monitored parameter, the 
applicable operating parameter limit, and the date and duration of the 
period that the excursion occurred.
    (B) For each excursion caused when the 365-day average condenser 
control efficiency is less than 95.0 percent, as specified in 
Sec. 63.773(d)(6)(ii), the report must include the 365-day average 
values of the condenser control efficiency, and the date and duration 
of the period that the excursion occurred.
    (C) For each excursion caused when condenser control efficiency is 
less than 90.0 percent, as calculated according to the procedures 
specified in Sec. 63.772(g)(2)(iii) (A) or (B), the report must include 
the average values of the condenser control efficiency, and the date 
and duration of the period that the excursion occurred.
    (D) For each excursion caused by lack of monitoring data, as 
specified in Sec. 63.773(d)(6)(iii), the report must include the date 
and duration of the period when the monitoring data were not collected 
and the reason why the data were not collected.
    (iii) For each inspection conducted in accordance with 
Sec. 63.773(c) during which a leak or defect is detected, the records 
specified in Sec. 63.774(b)(7) must be included in the next Periodic 
Report.
    (iv) For each owner or operator subject to the provisions specified 
in Sec. 63.769, the owner or operator shall comply with the reporting 
requirements specified in 40 CFR 61.247, except that the Periodic 
Reports shall be submitted on the schedule specified in paragraph 
(e)(1) of this section.
    (v) For each closed-vent system with a bypass line subject to 
Sec. 63.771(c)(3)(i)(A), records required under Sec. 63.774(b)(4)(iii) 
of all periods when the vent stream is diverted from the control device 
through a bypass line. For each closed-vent system with a bypass line 
subject to Sec. 63.771(c)(3)(i)(B), records required under 
Sec. 63.774(b)(4)(iv) of all periods in which the seal mechanism is 
broken, the bypass valve position has changed, or the key to unlock the 
bypass line valve was checked out.
    (vi) If an owner or operator elects to comply with 
Sec. 63.765(b)(1)(ii), the records required under Sec. 63.774(c)(3).
    (vii) The information in paragraphs (e)(2)(vii) (A) and (B) of this 
section shall be stated in the Periodic Report, when applicable.
    (A) No excursions.
    (B) No continuous monitoring system has been inoperative, out of 
control, repaired, or adjusted.
    (viii) Any change in compliance methods as specified in 
Sec. 63.772(f).
    (ix) If the owner or operator elects to comply with 
Sec. 63.765(c)(2), the records required under Sec. 63.774(b)(11).
    (f) Notification of process change. Whenever a process change is 
made, or

[[Page 32645]]

a change in any of the information submitted in the Notification of 
Compliance Status Report, the owner or operator shall submit a report 
within 180 days after the process change is made or as a part of the 
next Periodic Report as required under paragraph (e) of this section, 
whichever is sooner. The report shall include:
    (1) A brief description of the process change;
    (2) A description of any modification to standard procedures or 
quality assurance procedures;
    (3) Revisions to any of the information reported in the original 
Notification of Compliance Status Report under paragraph (d) of this 
section; and
    (4) Information required by the Notification of Compliance Status 
Report under paragraph (d) of this section for changes involving the 
addition of processes or equipment.


Sec. 63.776  Delegation of authority.

    (a) In delegating implementation and enforcement authority to a 
State under section 112(l) of the Act, the authorities contained in 
paragraph (b) of this section shall be retained by the Administrator 
and not transferred to a State.
    (b) Authorities will not be delegated to States for Secs. 63.772 
and 63.777 of this subpart.


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.
    (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]

Appendix to Subpart HH--Tables

 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                     Explanation
----------------------------------------------------------------------------------------------------------------
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) through (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) through (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)...................  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 in subpart HH.
Sec.  63.3(a) through (c)..........  Yes
Sec.  63.4(a)(1) through (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

[[Page 32646]]

 
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) through (c)(4)....  No.........................  Section reserved.
Sec.  63.6(c)(5)...................  Yes
Sec.  63.6(d)......................  No.........................  Section reserved.
Sec.  63.6(e)......................  Yes........................  Except as otherwise specified.
Sec.  63.6(e)(1)(i)................  No.........................  Addressed in Sec.  63.762.
Sec.  63.6(e)(1)(ii)...............  Yes
Sec.  63.6(e)(1)(iii)..............  Yes
Sec.  63.6(e)(2)...................  Yes
Sec.  63.6(e)(3)(i)................  Yes........................  Except as otherwise specified.
Sec.  63.6(e)(3)(i)(A).............  No.........................  Addressed by Sec.  63.762(c).
Sec.  63.6(e)(3)(i)(B).............  Yes
Sec.  63.6(e)(3)(i)(C).............  Yes
Sec.  63.6(e)(3)(ii) through         Yes
 (3)(vi).
Sec.  63.6(e)(3)(vii)..............
Sec.  63.6(e)(3)(vii)(A)...........  Yes
Sec.  63.6(e)(3)(vii)(B)...........  Yes........................  Except that the plan must provide for
                                                                   operation in compliance with Sec.  63.762(c).
Sec.  63.6(e)(3)(vii)(C)...........  Yes
Sec.  63.6(e)3)(viii)..............  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 HH does not require continuous
                                                                   emissions monitoring systems.
Sec.  63.6(i)(1) through (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

[[Page 32647]]

 
Sec.  63.8(c)(4)...................  No
Sec.  63.8(c)(5) through (c)(8)....  Yes
Sec.  63.8(d)......................  Yes
Sec.  63.8(e)......................  Yes........................  Subpart HH does not specifically require
                                                                   continuous emissions monitor performance
                                                                   evaluations, however, the Administrator can
                                                                   request that one be conducted.
Sec.  63.8(f)(1) through (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 1 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)......................  Yes
Sec.  63.9(g)......................  Yes
Sec.  63.9(h)(1) through (h)(3)....  Yes
Sec.  63.9(h)(4)...................  No.........................  Section reserved.
Sec.  63.9(h)(5) through (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) through (c)(4)...  No.........................  Sections reserved.
Sec.  63.10(c)(5) Through (c)(8)...  Yes
Sec.  63.10(c)(9)..................  No.........................  Section reserved.
Sec.  63.10(c)(10) through (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 HH requires major sources to submit a
                                                                   startup, shutdown and malfunction report semi-
                                                                   annually.
Sec.  63.10(e)(1)..................  Yes
Sec.  63.10(e)(2)..................  Yes
Sec.  63.10(e)(3)(i)...............  Yes........................  Subpart HH requires major sources to submit
                                                                   Periodic Reports semi-annually.
Sec.  63.10(e)(3)(i)(A)............  Yes
Sec.  63.10(e)(3)(i)(B)............  Yes
Sec.  63.10(e)(3)(i)(C)............  No.........................  Subpart HH does not require quarterly
                                                                   reporting for excess emissions.
Sec.  63.10(e)(3)(ii) through        Yes
 (viii).
Sec.  63.10(f).....................  Yes
Sec.  63.11(a) and (b).............  Yes
Sec.  63.12(a) through (c).........  Yes
Sec.  63.13(a) through (c).........  Yes
Sec.  63.14(a) and (b).............  Yes
Sec.  63.15(a) and (b).............  Yes
----------------------------------------------------------------------------------------------------------------

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

    3. 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  Startups, shutdowns, and malfunctions.
63.1273  [Reserved]
63.1274  General standards.
63.1275  Glycol dehydration unit process vent standards.
63.1276-63.1280  [Reserved]
63.1281  Control equipment requirements.
63.1282  Test methods, compliance procedures, and compliance 
demonstrations.
63.1283  Inspection and monitoring requirements.
63.1284  Recordkeeping requirements.
63.1285  Reporting requirements.
63.1286  Delegation of authority.
63.1287  Alternative means of emission limitation.

[[Page 32648]]

63.1288  [Reserved]
63.1289  [Reserved]
Appendix to Subpart HHH--Tables

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 and 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 (if there is no local distribution company), and that 
are major sources of hazardous air pollutants (HAP) emissions as 
determined using the maximum natural gas throughput calculated in 
either paragraph (a)(1) or (a)(2) of this section and paragraphs (a)(3) 
and (a)(4) of this section. A compressor station that transports 
natural gas prior to the point of custody transfer, or to a natural gas 
processing plant (if present) is considered a part of the oil and 
natural gas production source category. A facility that is determined 
to be an area source, based on emission estimates using the maximum 
natural gas throughput calculated as specified in paragraph (a)(1) or 
(a)(2) of this section, but subsequently increases emissions or 
potential to emit above the major source levels (without first 
obtaining and complying with other limitations that keep its potential 
to emit HAP below major source levels, becomes a major source and must 
comply thereafter with all applicable provisions of this subpart 
starting on the applicable compliance date specified in paragraph (d) 
of this section. Nothing in this paragraph is intended to preclude a 
source from limiting its potential to emit through other appropriate 
mechanisms that may be available through the permitting authority.
    (1) Facilities that store natural gas or facilities that transport 
and store natural gas shall determine major source status using the 
maximum annual facility natural gas throughput calculated according to 
paragraphs (a)(1)(i) through (a)(1)(iv) of this section.
    (i) The owner or operator shall determine the number of hours to 
complete the storage cycle for the facility. The storage cycle is the 
number of hours for the injection cycle, calculated according to the 
equation in paragraph (a)(1)(i)(A) of this section, plus the number of 
hours for the withdrawal cycle, calculated according to the equation in 
paragraph (a)(1)(i)(B) of this section.
    (A) The hours for the facility injection cycle are determined 
according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR17JN99.005

Where:

IC = Facility injection cycle in hours/cycle.
WGC = Working gas capacity in cubic meters. The working gas capacity is 
defined as the maximum storage capacity minus the FERC cushion (as 
defined in Sec. 63.1271).
IRmax = Maximum facility injection rate in cubic meters per 
hour.

    (B) The hours for the facility withdrawal cycle are determined 
according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR17JN99.006

Where:

WC = Facility withdrawal cycle, hours/cycle.
WGC = Working gas capacity, cubic meters. The working gas capacity is 
defined as the maximum storage capacity minus the FERC cushion (as 
defined in Sec. 63.1271) and shall be the same value as used in 
paragraph (a)(1)(i)(A) of this section.
WRmax = Maximum facility withdrawal rate in cubic meters per 
hour.

    (ii) The owner or operator shall calculate the number of storage 
cycles for the facility per year according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR17JN99.007

Where:

Cycle = Number of storage cycles for the facility per year.
IC = Number of hours for a facility injection cycle, hours/cycle, as 
calculated in paragraph (a)(1)(i)(A) of this section.
WC = Number of hours for a facility withdrawal cycle, hours/cycle, as 
calculated in paragraph (a)(1)(i)(B) of this section.
    (iii) The owner or operator shall calculate the facilitywide 
maximum annual glycol dehydration unit hours of operation based on the 
following equation:

Operation = Cycles  x  WC

Where:

Operation = Facilitywide maximum annual glycol dehydration unit hours 
of operation (hr/yr).
Cycles = Number of storage cycles for the facility per year, as 
calculated in paragraph (a)(1)(ii) of this section.
WC = Number of hours for a facility withdrawal cycle, hours/cycle, as 
calculated in paragraph (a)(1)(i)(B) of this section.

    (iv) The owner or operator shall calculate the maximum facilitywide 
natural gas throughput based on the following equation:

Throughput = Operation  x  WRmax

Where:

Throughput = Maximum facilitywide natural gas throughput in cubic 
meters per year.
Operation = Maximum facilitywide annual glycol dehydration unit hours 
of operation in hours per year, as calculated in paragraph (a)(1)(iii) 
of this section.
WRmax = Maximum facility withdrawal rate in cubic meters per 
hour.

    (2) Facilities that only transport natural gas shall calculate the 
maximum natural gas throughput as the highest annual natural gas 
throughput over the 5 years prior to June 17, 1999, multiplied by a 
factor of 1.2.
    (3) The owner or operator shall maintain records of the annual 
facility natural gas throughput each year and upon request, submit such 
records to the Administrator. If the facility annual natural gas 
throughput increases above the maximum natural gas throughput 
calculated in paragraph (a)(1) or (a)(2) of this section, the maximum 
natural gas throughput must be recalculated using the higher throughput 
multiplied by a factor of 1.2.

[[Page 32649]]

    (4) The owner or operator shall determine the maximum values for 
other parameters used to calculate potential emissions as the maximum 
over the same period for which maximum throughput is determined as 
specified in paragraph (a)(1) or (a)(2) of this section. These 
parameters shall be based on an annual average or the highest single 
measured value.
    (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 this provisions of the subpart no later than 
June 17, 2002 except as provided for in Sec. 63.6(i). The owner or 
operator of an area source, the construction or reconstruction of which 
commenced before February 6, 1998, that increases its emissions of (or 
its potential to emit) HAP such that the source becomes a major source 
that is subject to this subpart shall comply with this subpart 3 years 
after becoming a major source.
    (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 initial startup or June 17, 1999, whichever date is 
later. Area sources, the construction or reconstruction of which 
commences on or after February 6, 1998, that become major sources shall 
comply with the provisions of this standard immediately upon becoming a 
major source.
    (e) An owner or operator of an affected source that is a major 
source or is located at a major source and is subject to the provisions 
of this subpart is also subject to 40 CFR part 70 or part 71 permitting 
requirements.
    (f) Exemptions. A facility with a facilitywide actual annual 
average natural gas throughput less than 28.3 thousand standard cubic 
meters per day, where glycol dehydration units are the only HAP 
emission source, is not subject to the requirements of this subpart. 
Records shall be maintained as required in Sec. 63.10(b)(3).


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.
    Boiler means an enclosed device using controlled flame combustion 
and having the primary purpose of recovering and exporting thermal 
energy in the form of steam or hot water. Boiler also means any 
industrial furnace as defined in 40 CFR 260.10.
    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 one or more control devices. If gas or vapor from 
regulated equipment is routed to a process (e.g., to a fuel gas 
system), the conveyance system 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 organic HAP emissions.
    Compressor station means any permanent combination of compressors 
that 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 hour or records 
hourly or more frequent block average values.
    Control device means any equipment used for recovering or oxidizing 
HAP or volatile organic compounds (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 (i.e., injected into the flame zone of a combustion 
device), 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 or closed-vent systems.
    Custody transfer means the transfer of hydrocarbon liquids or 
natural gas:
    (1) After processing and/or treatment in the producing operations; 
or
    (2) From storage vessels or automatic transfer facilities, or other 
equipment, including product loading racks, to pipelines or any other 
forms of transportation.
    Facility means any grouping of equipment where natural gas is 
processed, compressed, or stored prior to entering a pipeline to a 
local distribution company or (if there is no local distribution 
company) to a final end user. Examples of a facility for this source 
category are: an underground natural gas storage operation; or a 
natural gas compressor station that receives natural gas via pipeline, 
from an underground natural gas storage operation, or from a natural 
gas processing plant. The emission points associated with these phases 
include, but are not limited to, process vents. Processes that may have 
vents include, but are not limited to, dehydration and compressor 
station engines.
    Facility, for the purpose of a major source determination, means 
natural gas transmission and storage equipment that is located inside 
the boundaries of an individual surface site (as defined in this 
section) and is connected by ancillary equipment, such as gas flow 
lines or power lines. Equipment that is part of a facility will 
typically be located within close proximity to other equipment located 
at the same facility. Natural gas transmission and storage equipment or 
groupings of equipment located on different gas leases, mineral fee 
tracts, lease tracts, subsurface unit areas, surface fee tracts, or 
surface lease tracts shall not be considered part of the same facility.
    Federal Energy Regulatory Commission Cushion or FERC Cushion means 
the minimum natural gas capacity of a storage field as determined by 
the Federal Energy Regulatory Commission.
    Flame zone means the portion of the combustion chamber in a 
combustion device occupied by the flame envelope.
    Flash tank. See the definition for gas-condensate-glycol (GCG) 
separator.
    Flow indicator means a device which indicates whether gas flow is 
present in

[[Page 32650]]

a line or whether the valve position would allow gas flow to be 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 
(including, but not limited to, ethylene glycol, diethylene glycol, or 
triethylene glycol) absorbent directly contacts a natural gas stream 
and absorbs water in a contact tower or absorption column (absorber). 
The glycol contacts and absorbs water vapor and other gas stream 
constituents from the natural gas and becomes ``rich'' glycol. This 
glycol is then regenerated in the glycol dehydration unit reboiler. The 
``lean'' glycol is then recycled.
    Glycol dehydration unit baseline operations means operations 
representative of the glycol dehydration unit operations as of June 17, 
1999. For the purposes of this subpart, for determining the percentage 
of overall HAP emission reduction attributable to process 
modifications, glycol dehydration unit baseline operations shall be 
parameter values (including, but not limited to, glycol circulation 
rate or glycol-HAP absorbency) that represent actual long-term 
conditions (i.e., at least 1 year). Glycol dehydration units in 
operation for less than 1 year shall document that the parameter values 
represent expected long-term operating conditions had process 
modifications not been made.
    Glycol dehydration unit process vent means either the glycol 
dehydration unit reboiler vent and the vent from the GCG separator 
(flash tank), if present.
    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 or to a control device.
    Hazardous air pollutants or HAP means the chemical compounds listed 
in section 112(b) of the Clean Air Act (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 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 is not 
physically formed into one manufactured or assembled unit with the 
combustion section; rather, the energy recovery section is 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 preheat the incoming vent stream or combustion air.
    Initial startup means the first time a new or reconstructed source 
begins production. For the purposes of this subpart, initial startup 
does not include subsequent startups (as defined in this section) of 
equipment, for example, following malfunctions or shutdowns.
    Major source, as used in this subpart, shall have the same meaning 
as in Sec. 63.2, except that:
    (1) Emissions from any pipeline compressor station 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 a naturally occurring mixture of hydrocarbon and 
nonhydrocarbon gases found in geologic formations beneath the earth's 
surface. The principal hydrocarbon constituent is methane.
    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 HAP from a device or 
system to the atmosphere as determined by:
    (1) Instrument monitoring results in accordance with the 
requirements of Sec. 63.1282(b); and
    (2) The absence of 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, indicates that an owner or operator has complied with 
an applicable operating parameter limitation, over the appropriate 
averaging period as specified in Sec. 63.1282 (e) and (f).
    Operating permit means a permit required by 40 CFR part 70 or part 
71.
    Organic monitoring device means an instrument used to indicate the 
concentration level of organic compounds exiting a control device based 
on a detection principle such as infra-red, photoionization, or thermal 
conductivity.
    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 an enclosed device using a controlled flame, 
the primary purpose of which is to transfer heat to a process fluid or 
process material that is not a fluid, or to a heat transfer material 
for use in a process (rather than for steam generation) .
    Safety device means a device that meets both of the following 
conditions: the device 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.
    Shutdown means for purposes including, but not limited to, periodic 
maintenance, replacement of equipment, or repair, the cessation of 
operation of a glycol dehydration unit, or other affected source under 
this subpart, or equipment required or used solely to comply with this 
subpart.
    Startup means the setting into operation of a glycol dehydration 
unit, or other affected equipment under this subpart, or equipment 
required or used to comply with this subpart. Startup includes initial 
startup and operation solely for the purpose of testing equipment.
    Storage vessel means a tank or other vessel that is designed to 
contain an accumulation of crude oil, condensate, intermediate 
hydrocarbon liquids, produced water, or other liquid, and is 
constructed primarily of non-earthen

[[Page 32651]]

materials (e.g., wood, concrete, steel, plastic) that provide 
structural support.
    Surface site means any combination of one or more graded pad sites, 
gravel pad sites, foundations, platforms, or the immediate physical 
location upon which equipment is physically affixed.
    Temperature monitoring device means an instrument used to monitor 
temperature and having a minimum accuracy of 2 percent of 
the temperature being monitored expressed in  deg.C, or 2.5 
 deg.C, whichever is greater. The temperature monitoring device may 
measure temperature in degrees Fahrenheit or degrees Celsius, or both.
    Total organic compounds or TOC, as used in this subpart, means 
those compounds which can be 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  Startups, shutdowns, and malfunctions.

    (a) The provisions set forth in this subpart shall apply at all 
times except during startups or shutdowns, during malfunctions, and 
during periods of non-operation of the affected sources (or specific 
portion thereof) resulting in cessation of the emissions to which this 
subpart applies. However, during the startup, shutdown, malfunction, or 
period of non-operation of one portion of an affected source, all 
emission points which can comply with the specific provisions to which 
they are subject must do so during the startup, shutdown, malfunction, 
or period of non-operation.
    (b) The owner or operator shall not shut down items of equipment 
that are required or utilized for compliance with the provisions of 
this subpart during times when emissions are being routed to such items 
of equipment, if the shutdown would contravene requirements of this 
subpart applicable to such items of equipment. This paragraph does not 
apply if the item of equipment is malfunctioning, or if the owner or 
operator must shut down the equipment to avoid damage due to a 
contemporaneous startup, shutdown, or malfunction of the affected 
source or a portion thereof.
    (c) During startups, shutdowns, and malfunctions when the 
requirements of this subpart do not apply pursuant to paragraphs (a) 
and (b) of this section, the owner or operator shall implement, to the 
extent reasonably available, measures to prevent or minimize excess 
emissions to the maximum extent practical. For purposes of this 
paragraph, the term ``excess emissions'' means emissions in excess of 
those that would have occurred if there were no startup, shutdown, or 
malfunction, and the owner or operator complied with the relevant 
provisions of this subpart. The measures to be taken shall be 
identified in the applicable startup, shutdown, and malfunction plan, 
and may include, but are not limited to, air pollution control 
technologies, recovery technologies, work practices, pollution 
prevention, monitoring, and/or changes in the manner of operation of 
the source. Back-up control devices are not required, but may be used 
if available.
    (d) The owner or operator shall prepare a startup, shutdown, or 
malfunction plan as required in Sec. 63.6(e)(3) except that the plan is 
not required to be incorporated by reference into the source's title V 
permit as specified in Sec. 63.6(e)(3)(i). Instead, the owner or 
operator shall keep the plan on record as required by 
Sec. 63.6(e)(3)(v). The failure of the plan to adequately minimize 
emissions during the startup, shutdown, or malfunction does not shield 
an owner or operator from enforcement actions.


Sec. 63.1273  [Reserved]


Sec. 63.1274  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. Reports 
may be submitted on electronic media.
    (c) Except as specified in paragraph (d) of this section, 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 specified in Sec. 63.1283, and
    (3) The recordkeeping and reporting requirements specified in 
Secs. 63.1284 and 63.1285.
    (d) Exemptions. The owner or operator is exempt from the 
requirements of paragraph (c) of this section if the criteria listed in 
paragraph (d)(1) or (d)(2) of this section are met. Records of the 
determination of these criteria must be maintained as required in 
Sec. 63.1284(d) of this subpart.
    (1) The actual annual average flow of gas to the glycol dehydration 
unit is less than 283 thousand standard cubic meters per day, as 
determined by the procedures specified in Sec. 63.1282(a)(1) of this 
subpart; or
    (2) The actual average emissions of benzene from the glycol 
dehydration unit process vents to the atmosphere are less than 0.90 
megagram per year as determined by the procedures specified in 
Sec. 63.1282(a)(2) of this subpart.
    (e) 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 part 70, the permit 
shall be obtained from the State authority. If a State operating permit 
program has not been approved, the owner or operator shall apply to the 
EPA Regional Office pursuant to part 71.
    (f) [Reserved]
    (g) In all cases where the provisions of this subpart require an 
owner or operator to repair leaks by a specified time after the leak is 
detected, it is a violation of this standard to fail to take action to 
repair the leak(s) within the specified time. If action is taken to 
repair the leak(s) within the specified time, failure of that action to 
successfully repair the leak(s) is not a violation of this standard. 
However, if the repairs are unsuccessful, a leak is detected and the 
owner or operator shall take further action as required by the 
applicable provisions of this subpart.


Sec. 63.1275  Glycol dehydration unit process vent standards.

    (a) This section applies to each glycol dehydration unit, subject 
to this subpart, with an actual annual average natural gas flowrate 
equal to or greater than 283 thousand standard cubic meters per day and 
with actual average benzene glycol dehydration unit process vent 
emissions equal to or greater than 0.90 megagrams per year.
    (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 either paragraph (b)(1)(i) or 
(b)(1)(ii) of this section.

[[Page 32652]]

    (i) The owner or operator shall connect the process vent to a 
control device or a combination of control devices through a closed-
vent system. The closed-vent system shall be designed and operated in 
accordance with the requirements of Sec. 63.1281(c). The control 
device(s) shall be designed and operated in accordance with the 
requirements of Sec. 63.1281(d).
    (ii) The owner or operator shall connect the process vent to a 
control device or a combination of control devices through a closed-
vent system and the outlet benzene emissions from the control device(s) 
shall be less than 0.90 megagrams per year. The closed-vent system 
shall be designed and operated in accordance with the requirements of 
Sec. 63.1281(c). The control device(s) shall be designed and operated 
in accordance with the requirements of Sec. 63.1281(d), except that the 
performance requirements specified in Sec. 63.1281(d)(1)(i) and (ii) do 
not apply.
    (2) One or more safety devices that vent directly to the atmosphere 
may be used on the air emission control equipment installed to comply 
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.
    (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 process vent are reduced by 95.0 percent 
through process modifications or a combination of process modifications 
and one or more control devices, in accordance with the requirements 
specified in Sec. 63.1281(e).
    (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 emissions to the atmosphere 
from the glycol dehydration unit process vent are reduced by one of the 
levels specified in paragraphs (c)(3)(i) through (c)(3)(ii), through 
the installation and operation of controls as specified in paragraph 
(b) (1) of this section.
    (i) HAP emissions are reduced by 95.0 percent or more.
    (ii) Benzene emissions are reduced to a level less than 0.90 
megagrams per year.


Sec. 63.1276-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 as required by the provisions of this subpart. Compliance 
with paragraphs (c) and (d) of this section will be determined by 
review of the records required by Sec. 63.1284, the reports required by 
Sec. 63.1285, by review of performance test results, and by 
inspections.
    (b) [Reserved]
    (c) Closed-vent system requirements. (1) The closed-vent system 
shall route all gases, vapors, and fumes emitted from the material in a 
HAP emissions 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) Properly install, calibrate, maintain, and operate a flow 
indicator at the inlet to the bypass device that could divert the 
stream away from the control device to the atmosphere that takes a 
reading at least once every 15 minutes, and that sounds an alarm when 
the bypass device is open such that the stream is being, or could be, 
diverted away from the control device to the atmosphere; or
    (B) Secure the bypass device valve installed at the inlet to the 
bypass device in the non-diverting 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 non-diverting position and 
the vent stream is not diverted through the bypass device.
    (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 (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 95.0 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 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); or
    (C) Operates at a minimum residence time of 0.5 second at a minimum 
temperature of 760  deg.C.
    (D) 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 95.0 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) [Reserved]
    (3) The owner or operator shall demonstrate that a control device 
achieves the performance requirements of paragraph (d)(1) of this 
section by following the procedures specified in Sec. 63.1282(d).
    (4) The owner or operator shall operate each control device in 
accordance with the requirements specified in paragraphs (d)(4)(i) and 
(ii) of this section.
    (i) Each control device used to comply with this subpart shall be 
operating at all times when gases, vapors, and fumes are vented from 
the emissions unit or units through the closed-vent system to the 
control device, as required under Sec. 63.1275, 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.
    (ii) For each control device monitored in accordance with the 
requirements of

[[Page 32653]]

Sec. 63.1283(d), the owner or operator shall demonstrate compliance 
according to the requirements of Sec. 63.1282(e), or (f) as applicable.
    (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) The spent carbon removed from the carbon adsorption system 
shall be either regenerated, reactivated, or burned in one of the units 
specified in paragraphs (d)(5)(ii)(A) through (d)(5)(ii)(G) of this 
section.
    (A) Regenerated or reactivated in a thermal treatment unit for 
which the owner or operator has been issued a final permit under 40 CFR 
part 270 that implements the requirements of 40 CFR part 264, subpart 
X.
    (B) Regenerated or reactivated in a thermal treatment unit equipped 
with and operating organic air emission controls in accordance with 
this section.
    (C) Regenerated or reactivated in a thermal treatment unit equipped 
with and operating organic air emission controls in accordance with a 
national emissions standard for HAP under another subpart in 40 CFR 
part 61 or this part.
    (D) Burned in a hazardous waste incinerator for which the owner or 
operator has been issued a final permit under 40 CFR part 270 that 
implements the requirements of 40 CFR part 264, subpart O.
    (E) Burned in a hazardous waste incinerator which the owner or 
operator has designed and operates in accordance with the requirements 
of 40 CFR part 265, subpart O.
    (F) Burned in a boiler or industrial furnace for which the owner or 
operator has been issued a final permit under 40 CFR part 270 that 
implements the requirements of 40 CFR part 266, subpart H.
    (G) Burned in a boiler or industrial furnace which the owner or 
operator has designed and operates in accordance with the interim 
status requirements of 40 CFR part 266, subpart H.
    (e) Process modification requirements. Each owner or operator that 
chooses to comply with Sec. 63.1275(c)(2) shall meet the requirements 
specified in paragraphs (e)(1) through (e)(3) of this section.
    (1) The owner or operator shall determine glycol dehydration unit 
baseline operations (as defined in Sec. 63.1271). Records of glycol 
dehydration unit baseline operations shall be retained as required 
under Sec. 63.1284(b)(9).
    (2) The owner or operator shall document, to the Administrator's 
satisfaction, the conditions for which glycol dehydration unit baseline 
operations shall be modified to achieve the 95.0 percent overall HAP 
emission reduction, either through process modifications or through a 
combination of process modifications and one or more control devices. 
If a combination of process modifications and one or more control 
devices are used, the owner or operator shall also establish the 
percent HAP reduction to be achieved by the control device to achieve 
an overall HAP emission reduction of 95.0 percent for the glycol 
dehydration unit process vent. Only modifications in glycol dehydration 
unit operations directly related to process changes, including, but not 
limited to, changes in glycol circulation rate or glycol-HAP 
absorbency, shall be allowed. Changes in the inlet gas characteristics 
or natural gas throughput rate shall not be considered in determining 
the overall HAP emission reduction.
    (3) The owner or operator that achieves a 95.0 percent HAP emission 
reduction using process modifications alone shall comply with paragraph 
(e)(3)(i) of this section. The owner or operator that achieves a 95.0 
percent HAP emission reduction using a combination of process 
modifications and one or more control devices shall comply with 
paragraphs (e)(3)(i) and (e)(3)(ii) of this section.
    (i) The owner or operator shall maintain records, as required in 
Sec. 63.1284(b)(10), that the facility continues to operate in 
accordance with the conditions specified under paragraph (e)(2) of this 
section.
    (ii) The owner or operator shall comply with the control device 
requirements specified in paragraph (d) of this section, except that 
the emission reduction achieved shall be the emission reduction 
specified in paragraph (e)(2) of this section.


Sec. 63.1282  Test methods, compliance procedures, and compliance 
demonstrations.

    (a) Determination of glycol dehydration unit flowrate or benzene 
emissions. The procedures of this paragraph shall be used by an owner 
or operator to determine glycol dehydration unit natural gas flowrate 
or benzene emissions to meet the criteria for the exemption from 
control requirements under Sec. 63.1274(d).
    (1) The determination of actual flowrate 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 natural gas flowrate to the glycol 
dehydration unit with an accuracy of plus or minus 2 percent or better. 
The owner or operator shall convert the annual natural gas flowrate to 
a daily average by dividing the annual flowrate by the number of days 
per year the glycol dehydration unit processed natural gas.
    (ii) The owner or operator shall document, to the Administrator's 
satisfaction, that the actual annual average natural gas flowrate to 
the glycol dehydration unit is less than 85 thousand standard cubic 
meters per day.
    (2) The determination of actual average 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. Emissions shall be 
determined either uncontrolled or with federally enforceable controls 
in place.
    (i) The owner or operator shall determine actual average benzene 
emissions using the model GRI-GLYCalcTM, Version 3.0 or 
higher, and the procedures presented in the associated GRI-
GLYCalcTM Technical Reference Manual. Inputs to the model 
shall be representative of actual operating conditions of the glycol 
dehydration unit and may be determined using the procedures documented 
in the Gas Research Institute (GRI) report entitled ``Atmospheric Rich/
Lean Method for Determining Glycol Dehydrator Emissions'' (GRI-95/
0368.1); 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 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 converted to megagrams 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

[[Page 32654]]

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) An owner or operator may choose to adjust or not adjust the 
detection instrument readings to account for the background organic 
concentration level. If an owner or operator chooses to adjust the 
instrument readings for the background level, the background level 
value must be determined according to the procedures in Method 21 of 40 
CFR part 60, appendix A.
    (6)(i) Except as provided in paragraph (b)(6)(i) of this section, 
the detection instrument shall meet the performance criteria of Method 
21 of 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 process fluid not each individual volatile organic 
compound in the stream. For process streams that contain nitrogen, air, 
or other inerts which are not organic hazardous air pollutants or 
volatile organic compounds, the average stream response factor shall be 
calculated on an inert-free basis.
    (ii) If no instrument is available at the facility that will meet 
the performance criteria specified in paragraph (b)(6)(i) of this 
section, the instrument readings may be adjusted by multiplying by the 
average response factor of the process fluid, calculated on an inert-
free basis as described in paragraph (b)(6)(i) of this section.
    (7) An owner or operator must determine if a potential leak 
interface operates with no detectable emissions using the applicable 
procedure specified in paragraph (b)(7)(i) or (b)(7)(ii) of this 
section.
    (i) If an owner or operator chooses not to adjust the detection 
instrument readings for the background organic concentration level, 
then the maximum organic concentration value measured by the detection 
instrument is compared directly to the applicable value for the 
potential leak interface as specified in paragraph (b)(8) of this 
section.
    (ii) If an owner or operator chooses to adjust the detection 
instrument readings for the background organic concentration level, the 
value of the arithmetic difference between the maximum organic 
concentration value measured by the instrument and the background 
organic concentration value as determined in paragraph (b)(5) of this 
section is compared with the applicable value for the potential leak 
interface as specified in paragraph (b)(8) of this section.
    (8) A potential leak interface is determined to operate with no 
detectable organic emissions if the organic concentration value 
determined in paragraph (b)(7) is less than 500 parts per million by 
volume.
    (c) [Reserved]
    (d) Control device performance test procedures. This paragraph 
applies to the performance testing of control devices. The owners or 
operators shall demonstrate that a control device achieves the 
performance requirements of Sec. 63.1281(d)(1) or (e)(3)(ii) using 
either a performance test as specified in paragraph (d)(3) of this 
section or a design analysis as specified in paragraph (d)(4) of this 
section. The owner or operator may elect to use the alternative 
procedures in paragraph (d)(5) of this section for performance testing 
of a condenser used to control emissions from a glycol dehydration unit 
process vent.
    (1) The following control devices are exempt from the requirements 
to conduct performance tests and design analyses under this section:
    (i) A flare that is designed and operated in accordance with 
Sec. 63.11(b);
    (ii) A boiler or process heater with a design heat input capacity 
of 44 megawatts or greater;
    (iii) A boiler or process heater into which the vent stream is 
introduced with the primary fuel or is used as the primary fuel;
    (iv) 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;
    (v) A hazardous waste incinerator for which the owner or operator 
has been issued a final permit under 40 CFR part 270 and complies with 
the requirements of 40 CFR part 264, subpart O, or has certified 
compliance with the interim status requirements of 40 CFR part 265, 
subpart O.
    (vi) A control device for which a performance test was conducted 
for determining compliance with a regulation promulgated by the EPA, 
and the test was conducted using the same methods specified in this 
section, and either no process changes have been made since the test, 
or the owner or operator can demonstrate that the results of the 
performance test, with or without adjustments, reliably demonstrate 
compliance despite process changes.
    (2) An owner or operator shall design and operate each flare in 
accordance with the requirements specified in Sec. 63.11(b) and in 
paragraphs (d)(2)(i) and (d)(2)(ii) of this section.
    (i) The compliance determination shall be conducted using Method 22 
of 40 CFR part 60, appendix A, to determine visible emissions.
    (ii) An owner or operator is not required to conduct a performance 
test to determine percent emission reduction or outlet organic HAP or 
TOC concentration when a flare is used.
    (3) For a performance test conducted to demonstrate that a control 
device meets the requirements of Sec. 63.1281(d)(1) or (e)(3)(ii), the 
owner or operator shall use the test methods and procedures specified 
in paragraphs (d)(3)(i) through (d)(3)(iv) of this section. The 
performance test shall be conducted according to the schedule specified 
in Sec. 63.7(a)(2), and the results of the performance test shall be 
submitted in the Notification of Compliance Status Report as required 
in Sec. 63.1285(d)(1)(ii).
    (i) Method 1 or 1A, 40 CFR part 60, appendix A, as appropriate, 
shall be used for selection of the sampling sites specified in 
paragraphs (d)(3)(i)(A) and (B) of this section. Any references to 
particulate mentioned in Methods 1 and 1A do not apply to this section.
    (A) To determine compliance with the control device percent 
reduction requirements specified in 
Sec. 63.1281(d)(1)(i)(A),(d)(1)(ii), or (e)(3)(ii), sampling sites 
shall be located at the inlet of the first control device and at the 
outlet of the final control device.
    (B) 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.
    (ii) The gas volumetric flowrate shall be determined using Method 
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
    (iii) To determine compliance with the control device percent 
reduction performance requirement in Sec. 63.1281(d)(1)(i)(A), 
63.1281(d)(1)(ii), or 63.1281(e)(3)(ii), the owner or operator shall 
use either Method 18, 40 CFR part 60, appendix A, or Method 25A, 40 CFR 
part 60, appendix A;

[[Page 32655]]

alternatively, any other method or data that have 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:
    (A) 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.
    (B) The mass rate of either TOC (minus methane and ethane) or total 
HAP (Ei, Eo) shall be computed.
    (1) The following equations shall be used:
    [GRAPHIC] [TIFF OMITTED] TR17JN99.008
    
    [GRAPHIC] [TIFF OMITTED] TR17JN99.009
    
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 = Flowrate of gas stream at the inlet and 
outlet of the control device, respectively, dry standard cubic meter 
per minute.
K2 = Constant, 2.494x10 -6 (parts per million) 
-1 (gram-mole per standard cubic meter) (kilogram/gram) 
(minute/hour), where standard temperature is 20 deg.C.

    (2) 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; or Method 25A, 40 CFR part 60, appendix A, shall be summed 
using the equations in paragraph (d)(3)(iii)(B)(1) of this section.
    (3) When the total HAP mass rate is calculated, only HAP chemicals 
listed in Table 1 of this subpart shall be summed using the equations 
in paragraph (d)(3)(iii)(B)(1) of this section.
    (C) The percentage of reduction in TOC (minus methane and ethane) 
or total HAP shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR17JN99.010

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 
(d)(3)(iii)(B) 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)(iii)(B) of this section, kilograms TOC per hour or kilograms HAP 
per hour.

    (D) 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.
    (iv) 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 either Method 18, 40 CFR part 60, 
appendix A; or Method 25A, 40 CFR part 60, appendix A, to measure 
either TOC (minus methane and ethane) or total HAP. Alternatively, any 
other method or data that have been validated according to Method 301 
of 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:
    (A) 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.
    (B) The TOC concentration or total HAP concentration shall be 
calculated according to paragraph (d)(3)(iv)(B)(1) or (d)(3)(iv)(B)(2) 
of this section.
    (1) 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] TR17JN99.011

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.

    (2) The total HAP concentration (CHAP) shall be computed 
according to the equation in paragraph (d)(3)(iv)(B)(1) of this 
section, except that only HAP chemicals listed in Table 1 of this 
subpart shall be summed.
    (C) The TOC concentration or total HAP concentration shall be 
corrected to 3 percent oxygen as follows:
    (1) The emission rate correction factor for 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.
    (2) The concentration corrected to 3 percent oxygen (Cc) 
shall be computed using the following equation:
[GRAPHIC] [TIFF OMITTED] TR17JN99.012

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.

    (4) For a design analysis conducted to meet the requirements of 
Sec. 63.1281(d)(1) or (e)(3)(ii), the owner or operator shall meet the 
requirements specified in paragraphs (d)(4)(i) and (d)(4)(ii) of this 
section. Documentation of the design analysis shall be submitted as a 
part of the Notification of Compliance Status Report as required in 
Sec. 63.1285(d)(1)(i).
    (i) The design analysis shall include analysis of the vent stream 
characteristics and control device

[[Page 32656]]

operating parameters for the applicable control device as specified in 
paragraphs (d)(4)(i) (A) through (F) of this section.
    (A) For a thermal vapor incinerator, the design analysis shall 
include the vent stream composition, constituent concentrations, and 
flowrate and shall establish the design minimum and average 
temperatures in the combustion zone and the combustion zone residence 
time.
    (B) For a catalytic vapor incinerator, the design analysis shall 
include the vent stream composition, constituent concentrations, and 
flowrate and shall establish the design minimum and average 
temperatures across the catalyst bed inlet and outlet, and the design 
service life of the catalyst.
    (C) For a boiler or process heater, the design analysis shall 
include the vent stream composition, constituent concentrations, and 
flowrate; 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.
    (D) For a condenser, the design analysis shall include the vent 
stream composition, constituent concentrations, flowrate, 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. As an alternative 
to the design analysis, an owner or operator may elect to use the 
procedures specified in paragraph (d)(5) of this section.
    (E) For a regenerable carbon adsorption, the design analysis shall 
include the vent stream composition, constituent concentrations, 
flowrate, 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 the 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.
    (F) For a nonregenerable carbon adsorption system, such as a carbon 
canister, the design analysis shall include the vent stream 
composition, constituent concentrations, flowrate, relative humidity, 
and temperature, and shall establish the design exhaust vent stream 
organic compound concentration level, capacity of the carbon bed, type 
and working capacity of activated carbon used for the 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.
    (ii) 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) of this section. The Administrator 
may choose to have an authorized representative observe the performance 
test.
    (5) As an alternative to the procedures in paragraphs (d)(3) and 
(d)(4)(i)(D) of this section, an owner or operator may elect to use the 
procedures documented in the GRI report entitled, ``Atmospheric Rich/
Lean Method for Determining Glycol Dehydrator Emissions,'' (GRI-95/
0368.1) as inputs for the model GRI-GLYCalcTM, Version 3.0 
or higher, to determine condenser performance.
    (e) Compliance demonstration for control devices performance 
requirements. This paragraph applies to the demonstration of compliance 
with the control device performance requirements specified in 
Sec. 63.1281(d)(1) and (e)(3)(ii). Compliance shall be demonstrated 
using the requirements in paragraphs (e)(1) through (e)(3) of this 
section. As an alternative, an owner or operator that installs a 
condenser as the control device to achieve the requirements specified 
in Sec. 63.1281(d)(2)(ii) or Sec. 63.1275(c)(2), may demonstrate 
compliance according to paragraph (f) of this section. An owner or 
operator may switch between compliance with paragraph (e) of this 
section and compliance with paragraph (f) of this section only after at 
least 1 year of operation in compliance with the selected approach. 
Notification of such a change in the compliance method shall be 
reported in the next Periodic Report, as required in Sec. 63.1285(e), 
following the change.
    (1) The owner or operator shall establish a site specific maximum 
or minimum monitoring parameter value (as appropriate) according to the 
requirements of Sec. 63.1283(d)(5)(i).
    (2) The owner or operator shall calculate the daily average of the 
applicable monitored parameter in accordance with Sec. 63.1283(d)(4).
    (3) Compliance is achieved when the daily average of the monitoring 
parameter value calculated under paragraph (e)(2) of this section is 
either equal to or greater than the minimum or equal to or less than 
the maximum monitoring value established under paragraph (e)(1) of this 
section.
    (f) Compliance demonstration with percent reduction performance 
requirements--condensers. This paragraph applies to the demonstration 
of compliance with the performance requirements specified in 
Sec. 63.1281(d)(1)(ii) for condensers. Compliance shall be demonstrated 
using the procedures in paragraphs (f)(1) through (f)(3) of this 
section.
    (1) The owner or operator shall establish a site-specific condenser 
performance curve according to the procedures specified in 
Sec. 63.1283(d)(5)(ii).
    (2) Compliance with the percent reduction requirement in 
Sec. 63.1281(d)(1)(ii) or Sec. 63.1275(c)(2) shall be demonstrated by 
the procedures in paragraphs (f)(2)(i) through (f)(2)(iii) of this 
section.
    (i) The owner or operator must calculate the daily average 
condenser outlet temperature in accordance with Sec. 63.1283(d)(4).
    (ii) The owner or operator shall determine the condenser efficiency 
for the current operating day using the daily average condenser outlet 
temperature calculated in paragraph (f)(2)(i) of this section and the 
condenser performance curve established in paragraph (f)(1) of this 
section.
    (iii) Except as provided in paragraphs (f)(2)(iii) (A), (B), and 
(D) of this section, at the end of each operating day the owner or 
operator shall calculate the 30-day average HAP emission reduction from 
the condenser efficiencies determined in paragraph (f)(2)(ii) of this 
section for the preceding 30 operating days. If the owner or operator 
uses a combination of process modifications and a condenser in 
accordance with the requirements of Sec. 63.1275(c)(2), the 30-day 
average HAP emission reduction shall be calculated using the emission 
reduction achieved through process modifications and the condenser 
efficiency determined in paragraph (f)(2)(ii) of this section, both for 
the preceding 30 operating days.
    (A) After the compliance date specified in Sec. 63.1270(f), an 
owner or operator of a facility that stores natural gas that has less 
than 30 days of data for determining the average HAP emission 
reduction, shall calculate the cumulative average at the end of the 
withdrawal season, each season, until 30 days of condenser operating 
data are

[[Page 32657]]

accumulated. For a facility that does not store natural gas, the owner 
or operator that has less than 30 days of data for determining average 
HAP emission reduction, shall calculate the cumulative average at the 
end of the calendar year, each year, until 30 days of condenser 
operating data are accumulated.
    (B) After the compliance date specified in Sec. 63.1270(f), an 
owner or operator that has less than 30 days of data for determining 
the average HAP emission reduction, compliance is achieved if the 
average HAP emission reduction calculated in paragraph (f)(2)(iii)(A) 
of this section, is equal to or greater than 95.0 percent.
    (C) For the purposes of this subpart, a withdrawal season begins 
the first time gas is withdrawn from the storage field after July 1 of 
the calendar year and ends on June 30 of the next calendar year.
    (D) Glycol dehydration units that are operated continuously have 
the option of complying with the requirements specified in 40 CFR 
63.772(g).
    (3) Compliance is achieved with the emission limitation specified 
in Sec. 63.1281(d)(1)(ii) or Sec. 63.1275(c)(2) if the average HAP 
emission reduction calculated in paragraph (f)(2)(iii) of this section 
is equal to or greater than 95.0 percent.


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) 
For each closed-vent system required to comply with this section, the 
owner or operator shall comply with the requirements of paragraphs 
(c)(2) through (7) of this section.
    (2) Except as provided in paragraphs (c) (5) and (6) of this 
section, each closed-vent system shall be inspected according to the 
procedures and schedule specified in paragraphs (c)(2) (i) and (ii) of 
this section.
    (i) For each closed-vent system joints, seams, or other connections 
that are permanently or semi-permanently sealed (e.g., a welded joint 
between two sections of hard piping or a bolted or gasketed ducting 
flange), the owner or operator shall:
    (A) Conduct an initial inspection according to the procedures 
specified in Sec. 63.1282(b) to demonstrate that the closed-vent system 
operates with no detectable emissions.
    (B) Conduct annual visual inspections for defects that could result 
in air emissions. Defects include, but are not limited to, visible 
cracks, holes, or gaps in piping; loose connections; or broken or 
missing caps or other closure devices. The owner or operator shall 
monitor a component or connection using the procedures specified in 
Sec. 63.1282(b) to demonstrate that it operates with no detectable 
emissions following any time the component or connection is repaired or 
replaced or the connection is unsealed.
    (ii) For closed-vent system components other than those specified 
in paragraph (c)(2)(i) of this section, the owner or operator shall:
    (A) Conduct an initial inspection according to the procedures 
specified in Sec. 63.1282(b) to demonstrate that the closed-vent system 
operates with no detectable emissions.
    (B) Conduct annual inspections according to the procedures 
specified in Sec. 63.1282(b) to demonstrate that the components or 
connections operate with no detectable emissions.
    (C) Conduct annual visual inspections for defects that could result 
in air emissions. Defects include, but are not limited to, visible 
cracks, holes, or gaps in ductwork; loose connections; or broken or 
missing caps or other closure devices.
    (3) In the event that a leak or defect is detected, the owner or 
operator shall repair the leak or defect as soon as practicable, except 
as provided in paragraph (c)(4) of this section.
    (i) A first attempt at repair shall be made no later than 5 
calendar days after the leak is detected.
    (ii) Repair shall be completed no later than 15 calendar days after 
the leak is detected.
    (4) Delay of repair of a closed-vent system for which leaks or 
defects have been detected is allowed if the repair is technically 
infeasible without a shutdown, as defined in Sec. 63.1271, or if the 
owner or operator determines that emissions resulting from immediate 
repair would be greater than the fugitive emissions likely to result 
from delay of repair. Repair of such equipment shall be completed by 
the end of the next shutdown.
    (5) Any parts of the closed-vent system or cover that are 
designated, as described in paragraphs (c)(5) (i) and (ii) of this 
section, as unsafe to inspect are exempt from the inspection 
requirements of paragraphs (c)(2) (i) and (ii) of this section if:
    (i) The owner or operator determines that the equipment is unsafe 
to inspect because inspecting personnel would be exposed to an imminent 
or potential danger as a consequence of complying with paragraph (c)(2) 
(i) or (ii) of this section; and
    (ii) The owner or operator has a written plan that requires 
inspection of the equipment as frequently as practicable during safe-
to-inspect times.
    (6) Any parts of the closed-vent system or cover that are 
designated, as described in paragraphs (c)(6) (i) and (ii) of this 
section, as difficult to inspect are exempt from the inspection 
requirements of paragraphs (c)(2) (i) and (ii) of this section if:
    (i) The owner or operator determines that the equipment cannot be 
inspected without elevating the inspecting personnel more than 2 meters 
above a support surface; and
    (ii) The owner or operator has a written plan that requires 
inspection of the equipment at least once every 5 years.
    (7) Records shall be maintained as specified in Sec. 63.1284(b)(5) 
through (8).
    (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 parameter 
monitoring system in accordance with the requirements of paragraphs 
(d)(3) through (9) of this section that will allow a determination to 
be made whether the control device is achieving the applicable 
performance requirements of Sec. 63.1281(d) or (e)(3). The continuous 
parameter monitoring system must meet the following specifications and 
requirements:
    (i) Each continuous parameter monitoring system shall measure data 
values at least once every hour and record either:
    (A) Each measured data value; or
    (B) Each block average value for each 1-hour period or shorter 
periods calculated from all measured data values during each period. If 
values are measured more frequently than once per minute, a single 
value for each minute may be used to calculate the hourly (or shorter 
period) block average instead of all measured values.
    (ii) The monitoring system must be installed, calibrated, operated, 
and maintained in accordance with the manufacturer's specifications or 
other written procedures that provide reasonable assurance that the 
monitoring equipment is operating properly.
    (2) An owner or operator is exempted from the monitoring 
requirements specified in paragraphs (d)(3) through (9) of this section 
for the following types of control devices:

[[Page 32658]]

    (i) A boiler or process heater in which all vent streams are 
introduced with the primary fuel or are used as the primary fuel;
    (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.
    (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 a minimum accuracy of 2 percent of the temperature 
being monitored in  deg.C, or 2.5  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 temperatures at two locations and have a minimum accuracy 
of 2 percent of the temperatures being monitored in  deg.C, 
or 2.5  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 a minimum accuracy of 2 percent of the 
temperature being monitored in  deg.C, or 2.5  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 a 
minimum accuracy of 2 percent of the temperature being 
monitored in  deg.C, or 2.5  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:
    (1) A continuous parameter monitoring system to measure and record 
the average total regeneration stream mass flow or volumetric flow 
during each carbon bed regeneration cycle. The integrating regenerating 
stream flow monitoring device must have an accuracy of 10 
percent; and
    (2) A continuous parameter monitoring system to measure and record 
the average carbon bed temperature for the duration of the carbon bed 
steaming cycle and to measure the actual carbon bed temperature after 
regeneration and within 15 minutes of completing the cooling cycle. The 
temperature monitoring device shall have a minimum accuracy of 
2 percent of the temperature being monitored in  deg.C, or 
2.5  deg.C, whichever value is greater.
    (G) For a nonregenerative-type carbon adsorption system, the owner 
or operator shall monitor the design carbon replacement interval 
established using a performance test performed in accordance with 
Sec. 63.1282(d)(3) or a design analysis in accordance with 
Sec. 63.1282(d)(4)(i)(F) and shall be based on the total carbon working 
capacity of the control device and source operating schedule.
    (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. The monitor must meet the requirements of Performance 
Specification 8 or 9 of appendix B of 40 CFR part 60 and must be 
installed, calibrated, and maintained according to the manufacturer's 
specifications.
    (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 (5).
    (4) Using the data recorded by the monitoring system, the owner or 
operator must calculate the daily average value for each monitored 
operating parameter for each operating day. If HAP emissions unit 
operation is continuous, the operating day is a 24-hour period. If the 
HAP emissions unit operation is not continuous, the operating day is 
the total number of hours of control device operation per 24-hour 
period. Valid data points must be available for 75 percent of the 
operating hours in an operating day to compute the daily average.
    (5) For each operating parameter monitored in accordance with the 
requirements of paragraph (d)(3) of this section, the owner or operator 
shall comply with paragraph (d)(5)(i) of this section for all control 
devices, and when condensers are installed, the owner or operator shall 
also comply with paragraph (d)(5)(ii) of this section for condensers.
    (i) 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(d)(1) or (e)(3)(ii). Each 
minimum or maximum operating parameter value shall be established as 
follows:
    (A) If the owner or operator conducts performance tests in 
accordance with the requirements of Sec. 63.1282(d)(3) to demonstrate 
that the control device achieves the applicable performance 
requirements specified in Sec. 63.1281(d)(1) or (e)(3)(ii), 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 or control device manufacturer's recommendations or a 
combination of both.
    (B) If the owner or operator uses a control device design analysis 
in accordance with the requirements of Sec. 63.1282(d)(4) to 
demonstrate that the control device achieves the applicable performance 
requirements specified in Sec. 63.1281(d)(1) or (e)(3)(ii), then the 
minimum operating parameter value or the maximum operating parameter 
value shall be established based on the control device design analysis 
and may be supplemented by the control device manufacturer's 
recommendations.
    (ii) The owner or operator shall establish a condenser performance 
curve showing the relationship between condenser outlet temperature and 
condenser control efficiency. The curve shall be established as 
follows:
    (A) If the owner or operator conducts a performance test in 
accordance with the requirements of Sec. 63.1282(d)(3) to demonstrate 
that the condenser achieves the applicable performance requirements in 
Sec. 63.1281(d)(1) or (e)(3)(ii), then the condenser performance curve 
shall be based on values measured during the performance test and 
supplemented as necessary by control device design analysis, or control 
device

[[Page 32659]]

manufacturer's recommendations, or a combination or both.
    (B) If the owner or operator uses a control device design analysis 
in accordance with the requirements of Sec. 63.1282(d)(4)(i)(D) to 
demonstrate that the condenser achieves the applicable performance 
requirements specified in Sec. 63.1281(d)(1) or (e)(3)(ii), then the 
condenser performance curve shall be based on the condenser design 
analysis and may be supplemented by the control device manufacturer's 
recommendations.
    (C) As an alternative to paragraphs (d)(5)(ii)(A) and (B) of this 
section, the owner or operator may elect to use the procedures 
documented in the GRI report entitled, ``Atmospheric Rich/Lean Method 
for Determining Glycol Dehydrator Emissions'' (GRI-95/0368.1) as inputs 
for the model GRI-GLYCalcTM, Version 3.0 or higher, to 
generate a condenser performance curve.
    (6) An excursion for a given control device is determined to have 
occurred when the monitoring data or lack of monitoring data result in 
any one of the criteria specified in paragraphs (d)(6)(i) through 
(d)(6)(iv) of this section being met. When multiple operating 
parameters are monitored for the same control device and during the 
same operating day, and more than one of these operating parameters 
meets an excursion criterion specified in paragraphs (d)(6)(i) through 
(d)(6)(iv) of this section, then a single excursion is determined to 
have occurred for the control device for that operating day.
    (i) An excursion occurs when the daily average value of a monitored 
operating parameter is less than the minimum operating parameter limit 
(or, if applicable, greater than the maximum operating parameter limit) 
established for the operating parameter in accordance with the 
requirements of paragraph (d)(5)(i) of this section.
    (ii) An excursion occurs when average condenser efficiency 
calculated according to the requirements specified in 
Sec. 63.1282(f)(2)(iii) is less than 95.0 percent, as specified in 
Sec. 63.1282(f)(3).
    (iii) An excursion occurs when the monitoring data are not 
available for at least 75 percent of the operating hours.
    (iv) 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, an excursion occurs when:
    (A) For each bypass line subject to Sec. 63.1281(c)(3)(i)(A) the 
flow indicator indicates that flow has been detected and that the 
stream has been diverted away from the control device to the 
atmosphere.
    (B) For each bypass line subject to Sec. 63.1281(c)(3)(i)(B), if 
the seal or closure mechanism has been broken, the bypass line valve 
position has changed, the key for the lock-and-key type lock has been 
checked out, or the car-seal has broken.
    (7) For each excursion, except as provided for in paragraph (d)(8) 
of this section, the owner or operator shall be deemed to have failed 
to have applied control in a manner that achieves the required 
operating parameter limits. Failure to achieve the required operating 
parameter limits is a violation of this standard.
    (8) An excursion is not a violation of the operating parameter 
limit as specified in paragraphs (d)(8)(i) and (d)(8)(ii) of this 
section.
    (i) An excursion does not count toward the number of excused 
excursions allowed under paragraph (d)(8)(ii) of this section when the 
excursion occurs during any one of the following periods:
    (A) During a period of startup, shutdown, or malfunction when the 
affected facility is operated during such period in accordance with the 
facility's startup, shutdown, and malfunction plan; or
    (B) During periods of non-operation of the unit or the process that 
is vented to the control device (resulting in cessation of HAP 
emissions to which the monitoring applies).
    (ii) For each control device, or combinations of control devices, 
installed on the same HAP emissions unit, one excused excursion is 
allowed per semiannual period for any reason. The initial semiannual 
period is the 6-month reporting period addressed by the first Periodic 
Report submitted by the owner or operator in accordance with 
Sec. 63.1285(e) of this subpart.
    (9) Nothing in paragraphs (d)(1) through (d)(8) of this section 
shall be construed to allow or excuse a monitoring parameter excursion 
caused by any activity that violates other applicable provisions of 
this subpart.


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 records specified in paragraphs (b)(1) through (b)(10) of 
this section:
    (1) The owner or operator of an affected source subject to the 
provisions of this subpart shall maintain files of all information 
(including all reports and notifications) required by this subpart. The 
files shall be retained for at least 5 years following the date of each 
occurrence, measurement, maintenance, corrective action, report or 
period.
    (i) All applicable records shall be maintained in such a manner 
that they can be readily accessed.
    (ii) The most recent 12 months of records shall be retained on site 
or shall be accessible from a central location by computer or other 
means that provides access within 2 hours after a request.
    (iii) The remaining 4 years of records may be retained offsite.
    (iv) Records may be maintained in hard copy or computer-readable 
form including, but not limited to, on paper, microfilm, computer, 
floppy disk, magnetic tape, or microfiche.
    (2) Records specified in Sec. 63.10(b)(2);
    (3) Records specified in Sec. 63.10(c) for each monitoring system 
operated by the owner or operator in accordance with the requirements 
of Sec. 63.1283(d). Notwithstanding the previous sentence, monitoring 
data recorded during periods identified in paragraphs (b)(2)(i) through 
(b)(2)(iv) of this section shall not be included in any average or 
percent leak rate computed under this subpart. Records shall be kept of 
the times and durations of all such periods and any other periods 
during process or control device operation when monitors are not 
operating.
    (i) Monitoring system breakdowns, repairs, calibration checks, and 
zero (low-level) and high-level adjustments;
    (ii) Startup, shutdown, and malfunction events. During startup, 
shutdown and malfunction events, the owner or operator shall maintain 
records indicating whether or not the startup, shutdown, or malfunction 
plan, required under Sec. 63.1272(d), was followed.
    (iii) Periods of non-operation resulting in cessation of the 
emissions to which the monitoring applies; and
    (iv) Excursions due to invalid data as defined in 
Sec. 63.1283(d)(6)(iii).
    (4) Each owner or operator using a control device to comply with 
Sec. 63.1274 shall keep the following records up-to-date and readily 
accessible:
    (i) Continuous records of the equipment operating parameters 
specified to be monitored under Sec. 63.1283(d) or specified by the 
Administrator in accordance with Sec. 63.1283(d)(3)(iii). For flares, 
the hourly records and records of pilot flame outages specified in 
Sec. 63.1283(d)(3)(i)(C) shall be maintained in place of continuous 
records.

[[Page 32660]]

    (ii) Records of the daily average value of each continuously 
monitored parameter for each operating day determined according to the 
procedures specified in Sec. 63.1283(d)(4) of this subpart. For flares, 
records of the times and duration of all periods during which all pilot 
flames are absent shall be kept rather than daily averages.
    (iii) Hourly records of whether the flow indicator specified under 
Sec. 63.1281(c)(3)(i)(A) was operating and whether flow was detected at 
any time during the hour, as well as records of the times and durations 
of all periods when the vent stream is diverted from the control device 
or the monitor is not operating.
    (iv) Where a seal or closure mechanism is used to comply with 
Sec. 63.1281(c)(3)(i)(B), hourly records of flow are not required. In 
such cases, the owner or operator shall record that the monthly visual 
inspection of the seals or closure mechanism has been done, and shall 
record the duration of all periods when the seal mechanism is broken, 
the bypass line valve position has changed, or the key for a lock-and-
key type lock has been checked out, and records of any car-seal that 
has broken.
    (5) Records identifying all parts of the closed-vent system that 
are designated as unsafe to inspect in accordance with 
Sec. 63.1283(c)(5), an explanation of why the equipment is unsafe to 
inspect, and the plan for inspecting the equipment.
    (6) Records identifying all parts of the closed-vent system that 
are designated as difficult to inspect in accordance with 
Sec. 63.1283(c)(6), an explanation of why the equipment is difficult to 
inspect, and the plan for inspecting the equipment.
    (7) For each inspection conducted in accordance with 
Sec. 63.1283(c), during which a leak or defect is detected, a record of 
the information specified in paragraphs (b)(7)(i) through (b)(7)(viii) 
of this section.
    (i) The instrument identification numbers, operator name or 
initials, and identification of the equipment.
    (ii) The date the leak or defect was detected and the date of the 
first attempt to repair the leak or defect.
    (iii) Maximum instrument reading measured by the method specified 
in Sec. 63.1283(c)(3) after the leak or defect is successfully repaired 
or determined to be nonrepairable.
    (iv) ``Repair delayed'' and the reason for the delay if a leak or 
defect is not repaired within 15 calendar days after discovery of the 
leak or defect.
    (v) The name, initials, or other form of identification of the 
owner or operator (or designee) whose decision it was that repair could 
not be effected without a shutdown.
    (vi) The expected date of successful repair of the leak or defect 
if a leak or defect is not repaired within 15 calendar days.
    (vii) Dates of shutdowns that occur while the equipment is 
unrepaired.
    (viii) The date of successful repair of the leak or defect.
    (8) For each inspection conducted in accordance with 
Sec. 63.1283(c) during which no leaks or defects are detected, a record 
that the inspection was performed, the date of the inspection, and a 
statement that no leaks or defects were detected.
    (9) Records of glycol dehydration unit baseline operations 
calculated as required under Sec. 63.1281(e)(1).
    (10) Records required in Sec. 63.1281(e)(3)(i) documenting that the 
facility continues to operate under the conditions specified in 
Sec. 63.1281(e)(2).
    (c) An owner or operator that elects to comply with the benzene 
emission limit specified in Sec. 63.1275(b)(1)(ii) shall document, to 
the Administrator's satisfaction, the following items:
    (1) The method used for achieving compliance and the basis for 
using this compliance method; and
    (2) The method used for demonstrating compliance with 0.90 
megagrams per year of benzene.
    (3) Any information necessary to demonstrate compliance as required 
in the methods specified in paragraphs (c)(1) and (c)(2) of this 
section.
    (d) An owner or operator that is exempt from control requirements 
under Sec. 63.1274(d) shall maintain the records specified in paragraph 
(d)(1) or (d)(2) of this section, as appropriate, for each glycol 
dehydration unit that is not controlled according to the requirements 
of Sec. 63.1274(c).
    (1) The actual annual average natural gas throughput (in terms of 
natural gas flowrate to the glycol dehydration unit per day), as 
determined in accordance with Sec. 63.1282(a)(1); or
    (2) The actual average benzene emissions (in terms of benzene 
emissions per year), as determined in accordance with 
Sec. 63.1282(a)(2).
    (e) Record the following when using a flare to comply with 
Sec. 63.1281(d):
    (1) Flare design (i.e., steam-assisted, air-assisted, or non-
assisted);
    (2) All visible emission readings, heat content determinations, 
flowrate measurements, and exit velocity determinations made during the 
compliance determination required by Sec. 63.1282(d)(2); and
    (3) All periods during the compliance determination when the pilot 
flame is absent.


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 information listed in paragraphs (b)(1) through (b)(6) 
of this section, except as provided in paragraph (b)(7) of this 
section.
    (1) The initial notifications required for existing affected 
sources under Sec. 63.9(b)(2) shall be submitted by 1 year after an 
affected source becomes subject to the provisions of this subpart or by 
June 17, 2000, whichever is later. Affected sources that are major 
sources on or before June 17, 2000 and plan to be area sources by June 
17, 2002 shall include in this notification a brief, nonbinding 
description of a schedule for the action(s) that are planned to achieve 
area source status.
    (2) The date of the performance evaluation as specified in 
Sec. 63.8(e)(2), required only if the owner or operator is requested by 
the Administrator to conduct a performance evaluation for a continuous 
monitoring system. A separate notification of the performance 
evaluation is not required if it is included in the initial 
notification submitted in accordance with paragraph (b)(1) of this 
section.
    (3) The planned date of a performance test at least 60 days before 
the test in accordance with Sec. 63.7(b). Unless requested by the 
Administrator, a site-specific test plan is not required by this 
subpart. If requested by the Administrator, the owner or operator must 
also submit the site-specific test plan required by Sec. 63.7(c) with 
the notification of the performance test. A separate notification of 
the performance test is not required if it is included in the initial 
notification submitted in accordance with paragraph (b)(1) of this 
section.
    (4) A Notification of Compliance Status Report as described in 
paragraph (d) of this section;
    (5) Periodic Reports as described in paragraph (e) of this section; 
and
    (6) 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 Periodic Report 
specified in paragraph (e) of this section.
    (7) Each owner or operator of a glycol dehydration unit subject to 
this subpart that is exempt from the control

[[Page 32661]]

requirements for glycol dehydration unit process vents in Sec. 63.1275, 
is exempt from all reporting requirements for major sources in this 
subpart for that unit.
    (c) [Reserved]
    (d) Each owner or operator of a source subject to this subpart 
shall submit a Notification of Compliance Status Report as required 
under Sec. 63.9(h) within 180 days after the compliance date specified 
in Sec. 63.1270(d). In addition to the information required under 
Sec. 63.9(h), the Notification of Compliance Status Report shall 
include the information specified in paragraphs (d)(1) through (d)(10) 
of this section. This information may be submitted in an operating 
permit application, in an amendment to an operating permit application, 
in a separate submittal, or in any combination of the three. If all of 
the information required under this paragraph have been submitted at 
any time prior to 180 days after the applicable compliance dates 
specified in Sec. 63.1270(d), a separate Notification of Compliance 
Status Report is not required. If an owner or operator submits the 
information specified in paragraphs (d)(1) through (d)(9) of this 
section at different times, and/or different submittals, later 
submittals may refer to earlier submittals instead of duplicating and 
resubmitting the previously submitted information.
    (1) If a closed-vent system and a control device other than a flare 
are used to comply with Sec. 63.1274, the owner or operator shall 
submit:
    (i) The design analysis documentation specified in 
Sec. 63.1282(d)(4) of this subpart if the owner or operator elects to 
prepare a design analysis; or
    (ii) If the owner or operator elects to conduct a performance test, 
the performance test results including the information specified in 
paragraphs (d)(1)(ii)(A) and (B) of this section. Results of a 
performance test conducted prior to the compliance date of this subpart 
can be used provided that the test was conducted using the methods 
specified in Sec. 63.1282(d)(3), and that the test conditions are 
representative of current operating conditions.
    (A) The percent reduction of HAP or TOC, or the outlet 
concentration of HAP or TOC (parts per million by volume on a dry 
basis), determined as specified in Sec. 63.1282(d)(3) of this subpart; 
and
    (B) The value of the monitored parameters specified in 
Sec. 63.1283(d) of this subpart, or a site-specific parameter approved 
by the permitting agency, averaged over the full period of the 
performance test.
    (2) If a closed-vent system and a flare are used to comply with 
Sec. 63.1274, the owner or operator shall submit performance test 
results including the information in paragraphs (d)(2)(i) and (ii) of 
this section.
    (i) All visible emission readings, heat content determinations, 
flowrate measurements, and exit velocity determinations made during the 
compliance determination required by Sec. 63.1282(d)(2) of this 
subpart, and
    (ii) A statement of whether a flame was present at the pilot light 
over the full period of the compliance determination.
    (3) The owner or operator shall submit one complete test report for 
each test method used for a particular source.
    (i) For additional tests performed using the same test method, the 
results specified in paragraph (d)(1)(ii) of this section shall be 
submitted, but a complete test report is not required.
    (ii) A complete test report shall include a sampling site 
description, description of sampling and analysis procedures and any 
modifications to standard procedures, quality assurance procedures, 
record of operating conditions during the test, record of preparation 
of standards, record of calibrations, raw data sheets for field 
sampling, raw data sheets for field and laboratory analyses, 
documentation of calculations, and any other information required by 
the test method.
    (4) For each control device other than a flare used to meet the 
requirements of Sec. 63.1274, the owner or operator shall submit the 
information specified in paragraphs (d)(4)(i) through (iii) of this 
section 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) or (e)(3)(ii).
    (ii) An explanation of the rationale for why the owner or operator 
selected each of the operating parameter values established in 
Sec. 63.1283(d)(5) of this subpart. 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. 63.1281(d)(1) or 
(e)(3)(ii).
    (iii) A definition of the source's operating day for purposes of 
determining daily average values of monitored parameters. The 
definition shall specify the times at which an operating day begins and 
ends.
    (5) Results of any continuous monitoring system performance 
evaluations shall be included in the Notification of Compliance Status 
Report.
    (6) After a title V permit has been issued to the owner or operator 
of an affected source, the owner or operator of such source shall 
comply with all requirements for compliance status reports contained in 
the source's title V permit, including reports required under this 
subpart. After a title V permit has been issued to the owner or 
operator of an affected source, and each time a notification of 
compliance status is required under this subpart, the owner or operator 
of such source shall submit the notification of compliance status to 
the appropriate permitting authority following completion of the 
relevant compliance demonstration activity specified in this subpart.
    (7) The owner or operator that elects to comply with the 
requirements of Sec. 63.1275(b)(1)(ii) shall submit the records 
required under Sec. 63.1284(c).
    (8) The owner or operator shall submit an analysis demonstrating 
whether an affected source is a major source using the maximum 
throughput calculated according to Sec. 63.1270(a).
    (9) The owner or operator shall submit a statement as to whether 
the source has complied with the requirements of this subpart.
    (10) The owner or operator shall submit the analysis prepared under 
Sec. 63.1281(e)(2) to demonstrate that the conditions by which the 
facility will be operated to achieve an overall HAP emission reduction 
of 95.0 percent through process modifications or a combination of 
process modifications and one or more control devices.
    (e) Periodic Reports. An owner or operator shall prepare Periodic 
Reports in accordance with paragraphs (e)(1) and (2) of this section 
and submit them to the Administrator.
    (1) An owner or operator shall submit Periodic Reports 
semiannually, beginning 60 operating days after the end of the 
applicable reporting period. The first report shall be submitted no 
later than 240 days after the date the Notification of Compliance 
Status Report is due and shall cover the 6-month period beginning on 
the date the Notification of Compliance Status Report is due.
    (2) The owner or operator shall include the information specified 
in paragraphs (e)(2)(i) through (viii) of this section, as applicable.
    (i) The information required under Sec. 63.10(e)(3). For the 
purposes of this

[[Page 32662]]

subpart and the information required under Sec. 63.10(e)(3), excursions 
(as defined in Sec. 63.1283(d)(6)) shall be considered excess 
emissions.
    (ii) A description of all excursions as defined in 
Sec. 63.1283(d)(6) of this subpart that have occurred during the 6-
month reporting period.
    (A) For each excursion caused when the daily average value of a 
monitored operating parameter is less than the minimum operating 
parameter limit (or, if applicable, greater than the maximum operating 
parameter limit), as specified in Sec. 63.1283(d)(6)(i), the report 
must include the daily average values of the monitored parameter, the 
applicable operating parameter limit, and the date and duration of the 
period that the excursion occurred.
    (B) For each excursion caused when the 30-day average condenser 
control efficiency is less than 95.0 percent, as specified in 
Sec. 63.1283(d)(6)(ii), the report must include the 30-day average 
values of the condenser control efficiency, and the date and duration 
of the period that the excursion occurred.
    (C) For each excursion caused by lack of monitoring data, as 
specified in Sec. 63.1283(d)(6)(iii), the report must include the date 
and duration of period when the monitoring data were not collected and 
the reason why the data were not collected.
    (iii) For each inspection conducted in accordance with 
Sec. 63.1283(c) during which a leak or defect is detected, the records 
specified in Sec. 63.1284(b)(7) must be included in the next Periodic 
Report.
    (iv) For each closed-vent system with a bypass line subject to 
Sec. 63.1281(c)(3)(i)(A), records required under 
Sec. 63.1284(b)(4)(iii) of all periods when the vent stream is diverted 
from the control device through a bypass line. For each closed-vent 
system with a bypass line subject to Sec. 63.1281(c)(3)(i)(B), records 
required under Sec. 63.1284(b)(4)(iv) of all periods in which the seal 
or closure mechanism is broken, the bypass valve position has changed, 
or the key to unlock the bypass line valve was checked out.
    (v) If an owner or operator elects to comply with 
Sec. 63.1275(b)(1)(ii), the records required under Sec. 63.1284(c)(3).
    (vi) The information in paragraphs (e)(2)(vi)(A) and (B) of this 
section shall be stated in the Periodic Report, when applicable.
    (A) No excursions.
    (B) No continuous monitoring system has been inoperative, out of 
control, repaired, or adjusted.
    (vii) Any change in compliance methods as specified in 
Sec. 63.1275(b).
    (viii) If the owner or operator elects to comply with 
Sec. 63.1275(c)(2), the records required under Sec. 63.1284(b)(10).
    (f) Notification of process change. Whenever a process change is 
made, or a change in any of the information submitted in the 
Notification of Compliance Status Report, the owner or operator shall 
submit a report within 180 days after the process change is made or as 
a part of the next Periodic Report as required under paragraph (e) of 
this section, whichever is sooner. The report shall include:
    (1) A brief description of the process change;
    (2) A description of any modification to standard procedures or 
quality assurance procedures;
    (3) Revisions to any of the information reported in the original 
Notification of Compliance Status Report under paragraph (d) of this 
section; and
    (4) Information required by the Notification of Compliance Status 
Report under paragraph (d) of this section for changes involving the 
addition of processes or equipment.


Sec. 63.1286  Delegation of authority.

    (a) In delegating implementation and enforcement authority to a 
State under section 112(l) of the Act, the authorities contained in 
paragraph (b) of this section shall be retained by the Administrator 
and not transferred to a State.
    (b) Authorities will not be delegated to States for Secs. 63.1282 
and 63.1287 of this subpart.


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]

Appendix to Subpart HHH--Tables

    Table 1.--List of Hazardous Air Pollutants (HAP) for Subpart HHH
------------------------------------------------------------------------
              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
75050..................................  Acetaldehyde
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 HHH.--Applicability of 40 CFR Part 63 General Provisions to Subpart HHH
----------------------------------------------------------------------------------------------------------------
    General provisions reference      Applicable to  subpart HHH                    Explanation
----------------------------------------------------------------------------------------------------------------
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) through (a)(8)....  Yes
Sec.  63.1(a)(9)...................  No.........................  Section reserved.
Sec.  63.1(a)(10)..................  Yes

[[Page 32663]]

 
Sec.  63.1(a)(11)..................  Yes
Sec.  63.1(a)(12) through (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 in subpart HHH.
Sec.  63.3(a) through (c)..........  Yes
Sec.  63.4(a)(1) through (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
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) and (c)(4)........  No.........................  Section reserved.
Sec.  63.6(c)(5)...................  Yes
Sec.  63.6(d)......................  No.........................  Section reserved.
Sec.  63.6(e)......................  Yes
Sec.  63.6(e)......................  Yes                          Except as otherwise specified.
Sec.  63.6(e)(1)(i)................  No.........................  Addressed in Sec.  63.1272.
Sec.  63.6(e)(1)(ii)...............  Yes
Sec.  63.6(e)(1)(iii)..............  Yes
Sec.  63.6(e)(2)...................  Yes
Sec.  63.6(e)(3)(i)................  Yes........................  Except as otherwise specified.
Sec.  63.6(e)(3)(i)(A).............  No.........................  Addressed by Sec.  63.1272(c).
Sec.  63.6(e)(3)(i)(B).............  Yes
Sec.  63.6(e)(3)(i)(C).............  Yes
Sec.  63.6(e)(3)(ii) through         Yes
 (3)(vi).
Sec.  63.6(e)(3)(vii)..............
Sec.  63.6(e)(3)(vii) (A)..........  Yes
Sec.  63.6(e)(3)(vii) (B)..........  Yes........................  Except that the plan must provide for
                                                                   operation in compliance with Sec.
                                                                   63.1272(c).
Sec.  63.6(e)(3)(vii) (C)..........  Yes
Sec.  63.6(e)3)(viii)..............  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

[[Page 32664]]

 
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) through (c)(8)....  Yes
Sec.  63.8(d)......................  Yes
Sec.  63.8(e)......................  Yes........................  Subpart HHH does not specifically require
                                                                   continuous emissions monitor performance
                                                                   evaluations, however, the Administrator can
                                                                   request that one be conducted.
Sec.  63.8(f)(1) through (f)(5)....  Yes
Sec.  63.8(f)(6)...................  No.........................  Subpart HHH does not require continuous
                                                                   emissions monitoring.
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 1 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) through (h)(3)....  Yes
Sec.  63.9(h)(4)...................  No.........................  Section reserved.
Sec.  63.9(h)(5) and (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) through (c)(4)...  No.........................  Sections reserved.
Sec.  63.10(c)(5) through (c)(8)...  Yes
Sec.  63.10(c)(9)..................  No.........................  Section reserved.
Sec.  63.10(c)(10) through (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 a
                                                                   startup, shutdown and malfunction report semi-
                                                                   annually.
Sec.  63.10(e)(1)..................  Yes
Sec.  63.10(e)(2)..................  Yes
Sec.  63.10(e)(3)(i)...............  Yes........................  Subpart HHH requires major sources to submit
                                                                   Periodic Reports semi-annually.
Sec.  63.10(e)(3)(i)(A)............  Yes
Sec.  63.10(e)(3)(i)(B)............  Yes
Sec.  63.10(e)(3)(i)(C)............  No.........................  Subpart HHH does not require quarterly
                                                                   reporting for excess emissions.
Sec.  63.10(e)(3)(ii) through        Yes
 (e)(3)(viii).
Sec.  63.10(f).....................  Yes
Sec.  63.11(a) and (b).............  Yes
Sec.  63.12(a) through (c).........  Yes
Sec.  63.13(a) through (c).........  Yes
Sec.  63.14(a) and (b).............  Yes
Sec.  63.15(a) and (b).............  Yes
----------------------------------------------------------------------------------------------------------------

[FR Doc. 99-12894 Filed 6-16-99; 8:45 am]
BILLING CODE 6560-50-P