EPA

Office of Air Quality

Pla nnin g a nd S ta nd a rds

C Air

lean

United StatesOffice of Air QualityEPA-453/R-99-004b

Environmental Protection Planning and Standards May 1999

Agency Research Triangle Park, NC 27711

Air

NATIONAL EMISSION 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

National Emission Standards for Hazardous Air Pollutants for Source Categories: Oil and

Natural Gas Production and Natural Gas Transmission and Storage

Background Information for

Promulgated Standards - Summary of

Public Comments and Responses

Emission Standards Division

U. S. Environmental Protection Agency

Office of Air and Radiation

Office of Air Quality Planning and Standards

Research Triangle Park, NC 27711

iii

May 1999

Disclaimer

This report is issued by the Office of Air Quality Planning and Standards, U. S.

Environmental Protection Agency. Mention of trade names and/or commercial products is not

intended to constitute endorsement or recommendation for use. Copies of this report are

available free of charge to Federal employees, current contractors and grantees, and nonprofit

organizations–as supplies permit–from the Library Services Office (MD-35), U. S.

Environmental Protection Agency, Research Triangle Park, NC 27711, (919-541-2777) or, for a

nominal fee, from the National Technical Information Service, 5285 Port Royal Road,

Springfield, Virginia 22161, (703-487-4650).
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v

ENVIRONMENTAL PROTECTION AGENCY

National Emission Standards for Hazardous Air Pollutants for Source Categories: Oil and

Natural Gas Production and Natural Gas Transmission and Storage 

Background Information for Promulgated Standards - 

Summary of Public Comments and Responses

01 The final National Emission Standards for Hazardous Air Pollutants (NESHAP) will regulate

emissions of hazardous air pollutants from oil and natural gas production and natural gas

transmission and storage . Only those operations that are part of major sources under

section 112(d) of the Clean Air Act as amended in 1990 will be regulated.

02 Copies of this document have been sent to the following Federal Departments: Labor, health

and Human Services, Defense, Transportation, Agriculture, Commerce, interior, and Energy;

the national Science Foundation; and the Council on environmental Quality; members of the

State and Territorial Air Pollution program Administrators; the Association of Local Air

Pollution Control Officials; EPA Regional Administrators; and other interested parties.

03 For additional information contact:

Mr. Greg Nizich

Waste and Chemical Processes Group (MD-13)

U. S. Environmental Protection Agency

Research Triangle Park, NC 27711

Telephone: (919) 541-3078

4. Paper copies of this document may be obtained from:

National Technical Information Service (NTIS)

5285 Port Royal Road

Springfield, VA 22161

Telephone: (703) 487-4650

U. S. EPA Library Services Office (MD-35)

U. S. Environmental Protection Agency

Research Triangle Park, NC 27711

5. Electronic copies of this document may be obtained from the EPA’s OAR Technology

Transfer Network website (TTNWeb). 

The TTNWeb is a collection of related Web sites containing information about many areas of

air pollution science, technology, regulation, measurement, and prevention. The TTNWeb is

directly accessible from the Internet via the World Wide Web at the following address:

http//www.epa.gov/ttn
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TABLE OF CONTENTS

Page

vii

1.0 SUMMARY ........................ 1-1

1.1 BACKGROUND .................... 1-1

1.2 SUMMARY OF SIGNIFICANT CHANGES SINCE PROPOSAL . . . 1-1

1.2.1 Area Source Regulation ......... 1-1

1.2.2 Definition of Facility ......... 1-2

1.2.3 Potential-to-Emit ............ 1-3

1.2.4 Averaging Periods ............ 1-6

1.2.5 Process Modifications .......... 1-7

1.2.6 Standards for Natural Gas Transmission and

Storage ................. 1-8

1.2.7 Monitoring, Recordkeeping, and Reporting

Requirements ............. 1-11

1.3 SUMMARY OF IMPACTS OF PROMULGATED ACTION .... 1-12

2.0 SUMMARY OF PUBLIC COMMENTS ............... 2-1

2.1 APPLICABILITY ................... 2-8

2.1.1 Determination of Major Source Status . . 2-8

2.1.2 Exemptions .............. 2-22

2.1.3 Other Applicability Issues ...... 2-40

2.2 DEFINITIONS ................... 2-47

2.2.1 Facility ............... 2-47

2.2.2 Other Comments on Definitions ..... 2-56

2.3 ASSOCIATED EQUIPMENT .............. 2-86

2.4 HAP EMISSION POINTS ............... 2-95

2.5 IMPACTS ..................... 2-100

2.5.1 Cost Impacts Including Production Recovery

Credits ................ 2-100

2.5.2 Environmental Impacts ......... 2-107

2.6 ECONOMIC ANALYSIS ................ 2-109

2.7 LEGAL ISSUES [OTHER THAN ISSUES ASSOCIATED WITH THE

EPA'S INTERPRETATION OF SECTION 112(n)(4)(A) AND (B)]

........................ 2-114

2.8 PERMIT ISSUES .................. 2-116

2.9 ENFORCEMENT ISSUES ............... 2-120

2.10 CONTROLS .................... 2-132

2.10.1 MACT Floor .............. 2-132

2.10.2 Averaging Period ........... 2-140

2.10.3 Process Vent Standards ........ 2-146

2.10.4 Equipment Leak Standards ....... 2-152

2.10.5 Control Device Requirements ...... 2-155

2.10.6 Storage Vessel Standards ....... 2-157

2.11 MONITORING, RECORDKEEPING, AND REPORTING .... 2-159

2.11.1 Monitoring Requirements ........ 2-161

2.11.2 Recordkeeping and Reporting Requirements ................... 2-181

2.12 TEST METHODS .................. 2-194

2.13 COMPLIANCE ................... 2-201

2.13.1 Compliance Procedures ......... 2-201

2.13.2 Compliance Determination ....... 2-205
TABLE OF CONTENTS

Page

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2.13.3 Compliance Dates ........... 2-219

2.14 WORDING OF REGULATIONS (OTHER THAN APPLICABILITY AND

DEFINITIONS) .................. 2-221

2.15 GENERAL PROVISIONS ............... 2-226

2.16 MISCELLANEOUS .................. 2-232

2.16.1 Health Effects ............ 2-232

2.16.2 Other Miscellaneous Comments ..... 2-237

2.17 GENERAL COMMENTS SPECIFIC TO SUBPART HHH (NOT OTHERWISE

ADDRESSED) ................... 2-240

2.18 COMMENTS RECEIVED ON THE JANUARY 15, 1999 SUPPLEMENTAL

NOTICE (64 FR 2611) ............... 2-254
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1.0 SUMMARY

1.1 BACKGROUND

On February 6, 1998, the Environmental Protection Agency

(EPA) proposed standards of performance for the oil and natural

gas production source category (63 FR 6288) under authority of

Section 111 of the Clean Air Act.

Public comments were requested on the proposal in the

Federal Register. There were 54 commenters composed mainly of

industry and trade associations. Also commenting were State and

local agencies, consultants and engineers, environmental groups,

and other interested parties.

The written comments were submitted, along with the

responses to these comments, are summarized in this document. 

The summary of comments and responses serves as the basis for the

revisions made to the standard between proposal and promulgation.

1.2 SUMMARY OF SIGNIFICANT CHANGES SINCE PROPOSAL

In response to comments received on the proposed standards,

several changes have been made to the final rules. A summary of

the substantive changes made since the proposal in response to

comments is provided in the following sections. Additional

information on the final rules is contained in the docket for

this rule (Air Docket A-94-04).

1.2.1 Area Source Regulation

In the February 6, 1998 Federal Register notice (63 FR

6291), the EPA gave notice of its intention to add oil and

natural gas production as an area source category, 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.
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Several comment letters were received regarding the area

source regulation. Since the regulation of area sources has been

deferred, summaries of these comment letters and the EPA's

responses to these comments are not included in this document.

1.2.2 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

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.

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.

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.
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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.

1.2.3 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 stating that the calculation of PTE 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). Other commenters recommended that the EPA should

provide a simplified approach to calculate PTE, which takes into

account design and operational limitations.

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
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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.

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.

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,
1-5

subpart R. After extended effort, the EPA found that the number

of variables was too extensive to allow development of a

manageable equation.

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.

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. 

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
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throughput below 28.3 thousand m3/day are exempt from

subpart HHH.

1.2.4 Averaging Periods

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, the final 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
1-7

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.

1.2.5 Process Modifications

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 §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.

The EPA agrees that owners or operators should be allowed to

achieve a 95.0 percent emission reduction using process
1-8

modifications or combinations of process modifications and one or

more control devices. Therefore, the final 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 rules require 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 final rules also require the owner or operator to

document facility operations and to provide this information in

the Periodic reports.

1.2.6 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. 
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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 less than

283 thousand 78 m3/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)
1-10

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 parts

per million by volume (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
1-11

limit and the 30-day averaging period for condensers provides

sufficient flexibility for owners and operators of existing

controlled glycol dehydration units.

1.2.7 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.
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(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

§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.

1.3 SUMMARY OF IMPACTS OF PROMULGATED ACTION

The EPA estimated that the final oil and natural gas

production standards will reduce nationwide emissions of HAP by

approximately 30,000 megagrams per year (Mg/yr) from existing

sources, and 3,000 Mg/yr from new sources. The final natural gas

transmission and storage standards are estimated to reduce

nationwide HAP emissions by 390 Mg/yr from existing sources. No

new sources are anticipated for the natural gas transmission and

storage source category after the effective date for new sources

and in the first three years following promulgation of the

subpart HHH.

The nationwide annual costs (including capital recovery) of

the final rule are estimated to be approximately $4.0 million per

year for existing major sources in the oil and natural gas

production source category and $300,000 per year for existing

natural gas transmission and storage major sources. The total
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annual costs for new major oil and natural gas production sources

was estimated to be approximately $400,000 per year. The

economic analysis determined that the oil and natural gas

production 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. In addition the imposition of regulatory

costs on the natural gas market has a negligible effect on

natural gas prices, output, employment, foreign trade, and

business profitability.

The secondary environmental impacts that occur as a result

of this rule are expected to be minimal in comparison to the

primary HAP reduction benefits from the implementation of the

control options. The rule encourages the use of emission

controls that recover hydrocarbon products (such as methane and

condensate) that can be used onsite for fuel or reprocessed for

sale.

The energy impacts associated with the operation of emission

control devices are not significant. The EPA estimated that the

annual energy requirements to be 38,000 kilowatt hours per year

and result from the operation of vapor collection and recovery

systems installed on storage vessels. The EPA estimated that

add-on control systems (e.g., condensers and flares) would not

require additional energy.
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2.0 SUMMARY OF PUBLIC COMMENTS

A total of 50 letters commenting on the proposed standard

and the background information document for the proposed standard

were received. A public hearing was not requested. A list of

commenters, their affiliations, and the EPA docket number

assigned to their correspondence is given in Table 2-1.

For the purpose of orderly presentation, the comments have

been categorized under the following topics:

1. APPLICABILITY

2. DEFINITIONS

3. ASSOCIATED EQUIPMENT

4. HAP EMISSION POINTS

5. IMPACTS

6. ECONOMIC ANALYSIS

7. LEGAL ISSUES [OTHER THAN ISSUES ASSOCIATED WITH THE EPA'S

INTERPRETATION OF SECTION 112(n)(4)(A) AND (B)]

8. PERMIT ISSUES

9. ENFORCEMENT ISSUES

10. CONTROLS

11. MONITORING, RECORDKEEPING, AND REPORTING

12. TEST METHODS

13. COMPLIANCE

14. WORDING OF REGULATIONS (OTHER THAN APPLICABILITY AND

DEFINITIONS)

15. GENERAL PROVISIONS

16. MISCELLANEOUS

17. GENERAL COMMENTS SPECIFIC TO SUBPART HHH (NOT OTHERWISE

ADDRESSED)

18. COMMENTS RECEIVED ON THE JANUARY 15, 1999 SUPPLEMENTAL

NOTICE (64 FR 2611)
TABLE 2-1 (continued)

2-2

TABLE 2-1. LIST OF COMMENTERS ON PROPOSED STANDARDS OF

PERFORMANCE FOR OIL AND NATURAL GAS PRODUCTION AND NATURAL GAS

TRANSMISSION AND STORAGE INDUSTRIES

Docket Item Numbera Commenter and Affiliation

IV-D-1 G. Von Bodungen

Louisiana Department of Environmental Quality

Office of Air Quality

P.O. Box 82135

Baton Rouge, Louisiana 70844

IV-D-2 G. Holliday

Holliday Environmental Services, Inc.

P.O. Box 2508

Bellaire, Texas 77402

IV-D-3 J. Henderson

TruTesT Analytical Consultants, Inc.

3500 North Causeway Boulevard, Suite 600

Metairie, Louisiana 70002

IV-D-4 R. Gow

Questar Corp.

P.O. Box 45433

Salt Lake City, Utah 84145

IV-D-5 T. LaSalle, HLP Engineering, Inc.

barryh@linknet.net (Via e-mail)

IV-D-6 S. Knis

The Dow Chemical Company

Midland, Michigan 48675

IV-D-7 V. Lajiness

The Coastal Corporation

500 Renaissance Center

Detroit, Michigan 48243

IV-D-8 W. Ebarb

Hi Trading and Transportation Group

IV-D-9 J. Matuszak

The Peoples Gas Light and Coke Company

130 East Randolph Drive

Chicago, Illinois 60601

IV-D-10 T. Hutchins

El Paso Energy Company

IV-D-11 R. Metcalf

Louisiana Mid-Continent Oil and Gas

Association

801 North Boulevard, Suite 201

Baton Rouge, Louisiana 70802

IV-D-12 A. Evans

Consumers Energy Company

1945 West Parnall Road

Jackson, Mississippi 49201
TABLE 2-1 (continued)

Docket Item Numbera Commenter and Affiliation

2-3

IV-D-13 C. Reheis

Western States Petroleum Association

1115 11th Street, Suite 150

Sacramento, California 95814

IV-D-14 T. Horn

Harding Lawson Associates

202 Central SE, Suite 200

Albuqureque, New Mexico 87102

IV-D-15 J. Cantrell

Gas Processors Association

6526 East 60th Street

Tulsa, Oklahoma 74145

IV-D-16 B. Price

Phillips Petroleum Company

Bartelsville, Oklahoma 74004

IV-D-17 R. Taylor

True Oil Company

P.O. Drawer 2360

Casper, Wyoming 82602

IV-D-18 M. Wax

Institute of Clean Air Companies

1660 L Street NW, Suite 1100

Washington, District of Columbia 20036

IV-D-19 W. Airey

Vorys, Sater, Seymour, and Pease LLP

52 East Gay Street

P.O. Box 1008

Columbus, Ohio 43216

IV-D-20 K. Beckett

Jackson & Kelly

1600 Laidley Tower

P.O. Box 553

Charleston, West Virginia 25322

IV-D-21 V. Ammirato

Columbia Gas Transmission

P.O. Box 1273

Charleston, West Virginia 25325

IV-D-22 R. Jones

American Petroleum Institute

1220 L Street, Northwest

Washington, District of Columbia 20005

IV-D-23 W. Flis

Exxon Company, U.S.A.

P.O. Box 2180

Houston, Texas 77252

IV-D-24 S. Waisley

U.S. Department of Energy

Washington, District of Columbia 20585
TABLE 2-1 (continued)

Docket Item Numbera Commenter and Affiliation

2-4

IV-D-25 D. McKinnon

Manufacturers of Emission Controls Association

1660 L Street, Northwest, Suite 1100

Washington, District of Columbia 20036

IV-D-26 W. Doyle

Marathon Oil Company

539 South Main Street

Findlay, Ohio 45840

IV-D-27 M. Atherton

Columbia Energy Group Service Corporation

12355 Sunrise Valley Drive, Suite 300

Reston, Virginia 20191

IV-D-28 C. Price

Chemical Manufacturers Association

1300 Wilson Boulevard

Arlington, Virginia 22209

IV-D-29 M. Chytilo

Environmental Defense Center

906 Garden Street

Santa Barbara, California 93101

IV-D-30 A. Lee

Texaco, Inc.

P.O. Box 509

Beacon, New York 12508

IV-D-31 L. Beal

Interstate Natural Gas Association of America

L. Traweek, American Gas Association

(This comment letter contains a printing error

in the topical report, please see item IV-G-13

for the correction to this problem.)

IV-D-32 M. Lev-On

ARCO

444 S. Flower Street

Los Angeles, California 90071

IV-D-33 M. McThomas

Independent Oil and Gas Association of West

Virginia

P.O. Box 1791

Charleston, West Virginia 25326

IV-D-34 W. Sellars

Chevron U.S.A. Production Company

P.O. Box 1635

Houston, Texas 77251

IV-D-35 M. Blair

Colorado Department of Public Health and

Environment

4300 Cherry Creek Drive, South

Denver, Colorado 80246
TABLE 2-1 (continued)

Docket Item Numbera Commenter and Affiliation

2-5

IV-D-36 B. Mathur

Illinois Environmental Protection Agency

IV-D-37 B. Freeman

Shell E&P Technology Company

Bellaire Technology Center

P.O. Box 481

Houston, Texas 77001

IV-D-38 M. Fish

Enron Oil & Gas Company

P.O. Box 4362

Houston, Texas 77210

IV-G-1 P. Cantle

Santa Barbara County (California) Air

Pollution Control District

26 Castilian Drive B-23

Goleta, California 93117

IV-G-2 J. Ives

Rocky Mountain Oil & Gas Association

1900 Grant Street, Suite 510

Denver, Colorado 80203

IV-G-3 C. Matthews

Interstate Oil and Gas Compact Commission

P.O. Box 53127

Oklahoma City, Oklahoma 73152

IV-G-5 R. White

TU Services, Inc.

1601 Bryan Street

Dallas, Texas 75201

IV-G-7 R. Jones

Dehy Condensers, Inc.

129 N. Glenwood Boulevard

Tyler, Texas 75702

IV-G-9 P. Bennett

KN Energy Inc.

One Allen Center

500 Dallas Street, Suite 500

Houston, Texas 77002

IV-G-11 B. Russell

Independent Petroleum Association of America

1101 Sixteenth Street, Northwest

Washington, District of Columbia 20036

IV-G-12 M. Fox

New Century Energies

P.O. Box 840

Denver, Colorado 80202
TABLE 2-1 (continued)

Docket Item Numbera Commenter and Affiliation

2-6

IV-G-13 L. Beal

Interstate Natural Gas Association of America 

10 G Street, Northeast, Suite 700

Washington, District of Columbia 20002

(This document is a correction of the printing

error in item IV-D-31.)

IV-G-14 Unsigned/Concerned citizen

IV-G-15 J. Courville

Louisiana Department of Environmental Quality

Air Quality Division

P.O. Box 82135

Baton Rouge, Louisiana 70884

IV-G-16 F. Dowling

Emission Testing Service, Inc.

P.O. Box 15075

Baton Rouge, Louisiana 70895

IV-G-17 J. Monfries

Metco Environmental

P.O. Box 598

Addison, Texas 75001

IV-G-36 Vincent D. Lajiness

Director, Environmental, Legislative, and

Regulatory Affairs

Coatal States Management

500 Renaissance Center

Detroit, MI 48243

IV-G-37 Mr. Philip Bennett

Manager, Government Affairs

KN Interstate Gas Transmission Co.

One Allen Center

500 Dallas Street, Suite 100

Houston, TX 77002

IV-G-38 Ms. Lisa Beal

Director, Environmental Affairs

Interstate Natural Gas Association of America

10 G Street, N.E. Suite 700

Washington, DC 20002

IV-G-39 Mr. Thomas D. Hutchins, P.E.

Director, Environmental, Health & Safety

El Paso Natural Gas Company

P.O. Box 1492

El Paso, TX 79978-1492

a The docket number for this project is A-94-04. Dockets are on

file at the EPA Headquarters in Washington, D.C.
2-7

2.1 APPLICABILITY

2.1.1 Determination of Major Source Status

Comment: Commenters IV-D-11, IV-D-13, IV-D-14, IV-D-15,

IV-D-19, IV-D-22, IV-D-34, IV-D-37, IV-G-03, and IV-G-05

suggested that any source currently covered by a Federally,

State, or otherwise enforceable limit (e.g., title V permit)

should be able to include the control efficiency of the control

device when calculating applicability to subparts HH and HHH.

Commenter IV-D-11 recommended that the EPA exempt facilities

that were determined to be minor sources under part 70 from the

major source definition. The commenter stated that not excluding

"controlled" sources from the major source definition is

inconsistent with the intent of section 112(a)(1) of the CAA. 

The commenter explained that several sources in Louisiana have

applied federally enforceable controls well before the date of

the proposal and that being considered "minor sources" under part

70, but "major sources" under this proposal is inconsistent for

these sources. The commenter stated that the two programs must

have identical interpretations of the term. According to the

commenter, Louisiana sources would be penalized for reducing

emissions several years before the proposal of the rule, which

sends the wrong signal to the regulated community.

Commenter IV-D-34 requested that the EPA specifically

require in §§63.760 and 63.771(d) that the potential to emit

(PTE) for an affected source be determined "considering all

controls and limitations at the source." Commenters IV-D-13 and

IV-D-37 stated that the following must be assumed:

C the control device was installed before the enforcement date

of the final national emission standards for hazardous air

pollutants (NESHAP); 

C the control device was installed pursuant to a State or

local air quality law, ordinance, rule, requirement or

company business practice that was in place before the

enforcement date of the final NESHAP; and 

C the operation and emission reductions achieved by the

control device are federally enforceable through a

facility's title V permit or through another means that

would ensure federal enforceability.
2-8

According to the commenters, their proposed criteria provide a

common sense method to calculate PTE for existing facilities that

have existing control devices and that have achieved early

emission reductions before the enforcement date of the final

NESHAP. The commenters further stated that their proposed

criteria also prevent a facility operator from avoiding the

intent of title III of the Clean Air Act (CAA).

Response: Facilities with HAP emissions equal to or greater

than the major source levels as established in the CAAA of 1990

are subject to the major source provisions of subpart HH. As

defined in §63.2 (subpart A), PTE estimates take into account

those controls installed due to regulatory requirements of 

Federally-enforceable programs, which are defined in §63.2 and

the part 70 permit programs. Therefore, facilities with

controlled HAP emissions less than the major source thresholds

would be considered area sources. Therefore, by referring to

§63.2 of subpart A (see Table 2), subparts HH and HHH already

contain the provisions requested by the commenters.

For additional information on limiting PTE for section 112

purposes and for other reasons, please refer to the following

memoranda: (1) January 25, 1995 Memorandum from John Seitz,

Director, OAQPS, entitled "Options for Limiting the Potential to

Emit (PTE) of a Stationary Source Under Section 112 and Title V

of the Clean Air Act;" (2) August 27, 1996 Memorandum from John

Seitz, Director, OAQPS, entitled "Extension of January 25, 1995

Potential to Emit Transition Policy;" and (3) July 10, 1998

Memorandum from John Seitz, Director, OAQPS, entitled "Second

Extension of January 25, 1995 Potential to Emit Transition Policy

and Clarification of Interim Policy."

Comment: Commenter IV-D-19 pointed to a court case

(National Mining Congress v. EPA, a59 F.3d.1351, D.C. Cir.1995)

where the District of Columbia (DC) Circuit Court of Appeals

ruled that the EPA had not adequately justified the requirement

in section 112 of the CAA that standards that place limits on PTE

must be "federally enforceable." The commenter suggested that

within this rulemaking, limits on PTE are not limited to those
2-9

that are "federally enforceable" as stated in the General

Provisions (40 CFR 63.2). According to the commenter, any

physical or operational limitation on the capacity of a source to

emit a pollutant is appropriate. The commenter also suggested

that the effect a limitation would have on emissions should be

either federally enforceable or legally and practically

enforceable by the State.

Response: In 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 MACT 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. 

Therefore, the EPA has not modified subparts HH and HHH in

response to this comment.

Comment: Commenters IV-D-08, IV-D-15, IV-D-17, IV-D-20,

IV-D-22, IV-D-23, IV-D-34, IV-G-03, and IV-G-05 were concerned

that PTE estimates, as defined in the General Provisions, would

be unrealistically high and would subject many small

insignificant sources to the maximum achievable control

technology (MACT) requirements. Commenter IV-G-03 was concerned

that the PTE calculations this would result in high costs for

controlling low emission sources, and may force marginally

economic wells into premature abandonment. These commenters,

along with commenters IV-D-04, IV-D-13, IV-D-19, IV-D-26,

IV-D-30, IV-D-31, and IV-G-11 requested that PTE be based on the

inherent design and operational limitations of production and

transmission and storage facilities, such as throughput rates. 

Commenter IV-D-04 suggested that Gas Research Institute

(GRI)--GLYCalcTM, Version 3.0 or higher (GLYCalc) would allow for

the inclusion of these operating conditions in determining

applicability for affected sources.

According to commenters IV-D-15, IV-D-22, IV-D-31, IV-D-34,

IV-G-02, IV-G-03, and IV-G-05, the throughput of oil and gas

production operations decline over time, and existing equipment
2-10

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. Commenter IV-D-15

remarked that the throughput or process rate of a unit is limited

by the oil or gas available in the geographic area where it is

located. The commenter explained that the product being handled

has unique chemical characteristics such as American Petroleum

Institute (API) gravity, gas-to-oil ratio (GOR), etc., which also

affect the emissions from a unit. The commenter further

explained that the other equipment at the site will also affect

the potential emissions of a unit (i.e., capping the potential

emissions).

According to commenters IV-D-05, IV-D-15, IV-D-22, IV-D-34,

IV-G-03, and IV-G-05, several States have established, through

their own permit programs, mechanisms to limit PTE. The

commenters requested that this MACT defer to State programs. The

commenters suggested that the methodology in the Texas Natural

Resource Conservation Commission's (TNRCC) Oil and Gas

Supplemental Guidance Memorandum be used to define the PTE at

inherently limited sources. According to commenter IV-D-15, to

calculate PTE using the TNRCC approach, the operator (1) averages

the highest site product throughput over the past five years, (2)

multiplies that average by 1.2 (raising the throughput 20 percent

covers the possibility if minor fluctuations or changes), and (3)

uses the highest impact chemical composition from the past five

years. Texas also defines calculation methods for inherently

limited emission units and documentation, monitoring and

recordkeeping requirements. Commenter IV-D-34 also noted that

Wyoming allows exploration and production facilities to adopt

design or other limitations under State regulations.

Commenter IV-D-22 also provided supplemental comments

(IV-G-23) and recommended that the EPA either (1) specify methods

for the oil and natural gas production source category to use in

calculating PTE or (2) provide a simple federal synthetic minor

source mechanism.
2-11

Response: 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 EPA has developed an approach for determining

whether or not a facility is a major source subject to

subpart HH. The final rule allows an owner or operator to

calculate potential emissions using a maximum annual facility

throughput that is calculated as follows:

1. If the owner or operator of a production facility documents,

to the Administrator's satisfaction, a decline in annual

natural gas or hydrocarbon liquid throughput, each year, for

the five years prior to the effective date of subpart HH,

the owner or operator must determine the maximum natural gas

or hydrocarbon liquid throughput as the average of the

annual natural gas or hydrocarbon liquid throughput for the

three years prior to the effective date of subpart HH,

multiplied by 1.2. This maximum throughput must be used to

determine a facility's PTE.

2. If the owner or operator cannot document a decline in annual

throughput each year for the five years prior to the

effective date of subpart HH, the maximum throughput used to

calculate PTE must be calculated as the highest annual

natural gas or hydrocarbon liquid throughput over the five

years prior to the effective date of subpart HH, multiplied

by a factor of 1.2.

3. The owner or operator is required to document annual

facility natural gas or hydrocarbon liquid throughput each

year and if the facility's natural gas or hydrocarbon liquid

throughput increases above the maximum throughput calculated

in steps (1) or (2), the maximum throughput must be

recalculated using the new, higher, throughput multiplied by

the factor of 1.2.

4. The owner or operator is also required to determine the

maximum values for other parameters used to calculate PTE as

the maximum for the period over which the maximum natural

gas or hydrocarbon liquid throughput is determined in steps

(1) or (2).

Comment: Commenters IV-D-07 and IV-D-31 requested that the

EPA 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
1

The FERC cushion is the minimum gas capacity allowed for a

storage field, as regulated by the Federal Energy Regulatory

Commission.

2-12

(1)

natural gas storage facilities must spend part of the year

injecting gas and that withdrawal rates decrease as the storage

field's pressure drops.

Response: The EPA agrees that natural gas storage

facilities have inherent limitations due to the nature of their

operations. Information collected during site visits indicated

that glycol dehydration units located at storage facilities

normally operate in the winter when gas is being withdrawn from

storage fields (Air Docket A-94-04 numbers IV-B-01 through

IV-B-05). Therefore, the EPA believes that it is not appropriate

for such facilities to estimate potential emissions based on

year-round operation (i.e., 8,760 hr/yr). Therefore the EPA has

developed the following procedure to determine major source

status and applicability to subpart HHH for facilities that store

natural gas or facilities that transport and store natural gas:

1. The owner or operator calculates the number of hours it

takes to complete a storage cycle for the facility. The

storage cycle is the number of hours for the injection

cycle, calculated using Equation 1, plus the number of hours

for the withdrawal cycle, calculated using Equation 2.

where:

IC = Facility injection cycle in hr/cycle.

WGC = Working gas capacity in m3. The working

gas capacity is defined as the maximum

storage capacity minus the FERC

cushion.1

IRmax = Maximum facility injection rate in

m3/hr.
2-13

(2)

(3)

(4)

where:

WC = Facility withdrawal cycle in hr/cycle.

WGC = Working gas capacity in m3 (same value

used in equation 1).

WRmax = Maximum facility withdrawal rate in

m3/hr.

2. The owner or operator calculates the number of storage

cycles per year using Equation 3.

where:

Cycle = Number of storage cycles for the

facility per year (cycle/facility/yr).

IC = Number of hours for a facility injection

cycle, calculated using Equation 1

(hr/cycle).

WC = Number of hours for a facility

withdrawal cycle, calculated using

Equation 2 (hr/cycle).

3. The owner or operator calculates the facilitywide maximum

annual glycol dehydration unit hours of operation calculated

using Equation 4.

where:

Operation = Facilitywide maximum annual glycol

dehydration unit hours of operation

(hr/yr).

Cycles = Number of storage cycles for the

facility per year, calculated in

Equation 3 (cycle/facility/yr).
2-14

(5)

WC = Number of hours for a facility

withdrawal cycle (hr/cycle) as

calculated in Equation 2.

4. The owner or operator calculates the maximum facilitywide

natural gas throughput using Equation 5.

where:

Throughput = Maximum facilitywide natural gas

throughput in m3/yr.

Operation = Maximum facilitywide annual glycol

dehydration unit hours of operation

in hr/yr, as calculated in Equation

4.

WRmax = Maximum facility withdrawal rate in

m3/hr.

Since transmission facilities do not spend part of the year

injecting gas into storage, the EPA believes that the approach

for storage facilities is not appropriate. Therefore, the EPA

has included different requirements in subpart HHH for these

facilities to account for year-round operation. For facilities

that only transport natural gas, the final subpart HHH requires

owners or operators to calculate the maximum facility natural gas

throughput as the highest annual natural gas throughput over the

five years prior to the effective date of the rule, multiplied by

1.2.

The final subpart HHH also contains requirements for

determining maximum values for other parameters used to

calculated potential emissions and for documenting annual

facility natural gas throughput. These requirements are the same

as those specified for production.

Comment: Commenters IV-D-22, IV-D-26, IV-D-30, IV-D-34,

IV-G-02, and IV-G-11 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 (e.g., Gasoline Distribution, 40 CFR

part 63, subpart R).
2-15

Commenter IV-D-26 mentioned the possibility of a source

category-specific definition for PTE. Commenter IV-G-02 stated

that a simplified PTE analysis should be available for

determining applicability to subparts HH and HHH for the

following reasons:

C oil and gas equipment may be oversized compared with its

available throughput (due to field depletion or future field

development plans), C operators must make decisions on several sources, and C the EPA's definition of what must be aggregated in subparts

HH and HHH for a major source determination can be different

from the basis for major source determination for title V

(63 FR 6300 - 6303 cited).

Commenter IV-D-22 recommended that §63.760(c) be amended to

include the following text:

(1) The owner or operator of an affected source may demonstrate

that the source is an area source for all purposes under

this subpart by documenting and recording as required that

either:

(i) [Reserved for screening equations, e.g., the result "x"

of the following equation is "y"]; or

(ii) Specific operational or physical limitations adopted

for the source result in an area source classification. 

Such limitations may include (1) parameters of the

hydrocarbon fluid, (2) operating/production parameters

of the facility, (3) parameters of the hydrocarbon

reservoir, and (4) any other reasonable and enforceable

parameter.

(2) An area source classification established pursuant to these

criteria shall be treated as part of the design of the

source if it is federally, state, or otherwise practically

enforceable.

The commenter recommended that the EPA create a process within

subpart HH that streamlines the specification of enforceable

applicability criteria as referenced in modified §63.760(c)(ii),

above. The commenter stated that they will submit supplemental

comments providing appropriate criteria and outlining an

appropriate methodology for establishing this process. In their

supplemental comments (Air Docket A-94-04, number IV-G-23), the

commenter recommended a screening process for determining major

source status. This process included steps to (1) evaluated the
2-16

source status of glycol dehydration units, (2) evaluate the

source status for storage vessels, and (3) evaluate the source

status of collocated equipment. The commenter also made

recommendations monitoring, recordkeeping and reporting

requirements.

Response: 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.

Therefore, as an alternative, the EPA has 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, in addition to the

PTE approach outlined in a previous comment. The simplified MSD

allows the owner or operator of a facility to easily determine

(1) if they are major sources and whether MACT requirements apply

to their facility, and (2) if they are required to obtain a title

V operating permit.

The objective of the simplified MSD is to set applicability

thresholds that would reasonably ensure that no facilities

operating below such a threshold would have HAP emissions greater

than the major source thresholds of 10 tpy for individual HAP and

25 tpy for any combination of HAP as defined in the CAA. A

detailed description of the development of this MSD is presented

in the docket (Air Docket A-94-04 number IV-A-12).

To develop this MSD, the EPA reviewed "reasonable worst

case" scenarios for use in development of the simplified MSD

applicability levels. These "reasonable worst case" scenarios

take into account such variables as throughput, HAP

concentrations, and standard operating procedures.

Based on these scenarios, the EPA determined that oil and

natural gas production facilities prior to the point of custody

transfer, with a facilitywide actual annual average natural gas

throughput less than 650 thousand standard cubic feet per day

(scf/d) can be reasonable expected not to exceed the major source
2-17

thresholds. Likewise, the EPA determined that oil and natural

gas production facilities prior to the point of custody transfer

with a facilitywide hydrocarbon liquid throughput less than 250

bpd can reasonably be expected not to exceed the major source

thresholds.

Storage vessels make up a small percentage of emissions from

a production facility and have different emission profiles as

compared to glycol dehydration units. Therefore, the EPA

determined that a production facility consisting of glycol

dehydration units and storage vessels that meet the 650

thousand-scf/d natural gas throughput and the 250-bpd hydrocarbon

liquid throughput thresholds can be expected not to exceed the

major source thresholds.

Section 63.760 of final subpart HH contains an exemption

that states that production facilities prior to the point of

custody transfer, with a facilitywide natural gas throughput less

than 650 thousand scf/d and a facilitywide hydrocarbon liquid

throughput less than 250 bpd are exempt from subpart HH.

Owners and operators of production facilities after the

point of custody transfer (including natural gas processing

plants) are required to aggregate emissions from all HAP

emissions units at the facility when determining whether or not a

facility is a major source. Furthermore, production facilities

after the point of custody transfer are likely to have other HAP

emission units in addition to glycol dehydration units and

storage vessels, such as amine treaters and sulfur recovery units

which are typically located at natural gas processing plants. 

Since emissions from these emission points must be aggregated in

determining the major source status of the facility, the EPA

determined that it would be unreasonable to develop a throughput

cutoff that would reasonably ensure that facilities operating

below such cutoff would not be a major source. Therefore,

production facilities located after the point of custody

transfer, including natural gas processing plants, do not qualify

for the simplified MSD.
2-18

Using this same approach, the EPA determined that natural

gas transmission and storage facilities with a facilitywide

actual annual average natural gas throughput less than 1 million

standard cubic feet per day (MMscf/d), can reasonably be expected

not to exceed the major source thresholds (Air Docket A-94-04

number IV-A-15). Section 63.1270 of final subpart HHH states

that facilities operating with an actual average annual natural

gas throughput less than 1 MMscf/d are exempt from subpart HHH. 

However, since owners or operators of facilities in the natural

gas transmission and storage source category must aggregate

emissions from all HAP emissions units to determine major source

status, this exemption only applies to facilities where glycol

dehydration units are the only HAP emissions unit.

Comment: Commenter IV-D-26 recommended using the logic in

the EPA's 1995 Potential to Emit Transition Policy. Under this

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. Commenters IV-D-08, IV-D-20, and

IV-D-22 suggested the use of written documentation of physical

and operational limitations that would be federally, State, or

otherwise practically enforceable. The commenters recommended

that the EPA provide operators the ability to select maximum

annual levels for product throughput, and continuous maximums for

physical parameters of the product received and operating

parameters under which the unit will be operated. The operator

would then calculate PTE based on these maximums using accepted

calculation procedures (e.g., Vasquez-Beggs, or GLYCalc) and MACT

would apply if the aggregate PTE calculated based on maximums

exceeds the major source thresholds.

Response: 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 (this memorandum is available on the EPA's web site

at Internet address http://www.epa.gov/ttn/oarpg/t5pgm.html). 

This transition policy addressed concerns that some sources may
2-19

face gaps in the ability to acquire federally enforceable PTE

limits because of delays in State adoption of 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, for 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 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, this transition policy was extended until

July 31, 1998 (Internet site

http://www.epa.gov/ttn/oarpg/t5pgm.html). On July 10, 1998, in a

memorandum entitled "Second Extension of January 25, 1995

Potential to Emit Transition Policy and Clarification of Interim

Policy" (Internet site http://www.epa.gov/ttn/oarpg/t5pgm.html),

the EPA announced a second extension of the transition policy. 

These 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. These 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,

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. 
2-20

The EPA expects that the rulemaking will be completed before

December 31, 1999, and owners or operators will have the option

of complying with the PTE rulemaking as well as the procedures

specified in subparts HH and HHH.

2.1.2 Exemptions

Black Oil

Comment: Commenters IV-D-17 and IV-D-24 were concerned

about the exemption criteria for facilities that process, store,

or transfer black oil. Commenter IV-D-24 supported the use of a

black oil exemption in the proposed standards. Commenter IV-D-17

suggested that pipelines that transmit "black oil" should not be

further considered a potential HAP source. 

Response: As stated in the preamble to the proposed rule,

pipelines that handle hydrocarbon liquids after the point of

custody transfer are not within the scope of the oil and natural

gas production source category (63 FR 6291). The EPA plans to

define the organic liquids distribution (non-gasoline) source

category to include those facilities that distribute hydrocarbon

liquids after the point of custody transfer. Since black oil is

defined as a hydrocarbon liquid, facilities that transmit black

oil after the point of custody transfer will be covered under the

organic liquids distribution NESHAP. The EPA does not believe

that addressing this issue within subpart HH is necessary.

Comment: Commenters IV-D-20 and IV-D-33 questioned the

EPA's basis for the definition of black oil in subpart HH. 

Commenter IV-D-20 stated that it was unclear whether this

definition was based upon an assessment of HAP emissions or upon

the determination that black oil that meets this definition in

certain quantities and stored in a specific manner would result

in adverse impact upon human health and/or the environment.

Commenters IV-D-12, IV-D-33, and IV-D-38 requested changes

to the GOR and API gravity cutoffs proposed in the definition of

black oil in subpart HH. To be consistent with industry

practice, commenter IV-D-12 requested that the definition of

black oil be revised to a GOR of less than 5,000 standard cubic
2

McCain, William D. "Heavy Components Control Reservoir

Fluid Behavior." Journal of Petroleum Technology. September

1994. pages 746-750.

3

McCain, William D. "Black Oils and Volatile Oils - What's

the Difference." Petroleum Engineer International. November

1993. pages 24-27.

2-21

feet per barrel (scf/bbl) and commenters IV-D-12 and IV-D-38

requested an API gravity less than 50o. Commenter IV-D-33

requested that the threshold be changed from an API gravity of

40o to 45o, which would provide additional regulatory relief to

producers already hindered by marginal production in the

Appalachian region. According to the commenter, Appalachian

Basin crude oil runs between 40 and 45o. [Note: The commenter

had 45o instead of 40o as the proposed specific gravity

threshold. A typographical error is likely.]

Response: During the development of proposed subpart HH,

industry representatives 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 evaluated the available

information and agreed that facilities that process black oil

were not significant sources of overall HAP emissions from the

source category. Therefore, the EPA developed an exemption for

facilities that exclusively process, handle and store black oil.

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 was no control. This

determination was not made based on health risks associated with

black oil.

The EPA developed the definition for black oil (Air Docket 

A-94-04 number IV-A-05) based on a series of articles by William

D. McCain (primary author).2,3

 According to the information in

these articles, five types of reservoir fluids exist: black oil,

volatile oil, retrograde gas-condensate, wet gas, and dry gas. 

Of these, black oils and volatile oils exist as liquids in the
4

 Reference 2.

2-22

reservoir. Black oil, which is a mixture of chemical species

ranging from methane to large, heavy, nonvolatile molecules, is

in solution with dry gas, which is primarily methane.4

 Volatile

oils, which contain fewer heavy molecules, are in solution with

retrograde gas, which has fewer of the heavy organic molecules.

Reservoir fluid types are indicated by rules of thumb based

on initial producing GOR, stock-tank liquid gravity, and

stock-tank liquid color. Fluid type is usually determined by

initial producing GOR and can be confirmed using stock-tank

gravity and color. [Note: The distinction between initial

producing GOR and producing GOR is important. As reservoir

pressure decreases 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 oils is an initial producing GOR of at least

1,750 scf/bbl. Volatile oil is also suspected with a gravity of

40o or more and a color that is brown, reddish, orange, or green. 

The rule-of-thumb for black oil is an initial producing GOR less

than 1,750 scf/bbl and an API gravity less than 45o and a color

that is dark, usually black (sometimes with a greenish cast) or

brown.

The EPA used the descriptions of black oil from these

articles to develop the proposed definition of black oil. Since

color determination is subjective, the EPA selected initial

producing GOR and API gravity as quantifiable criteria for

defining black oil. In addition, since the API gravity criteria

overlap for black oil and volatile oil, the EPA chose the lower,

more conservative value of 40o for the black oil definition. The

EPA believes that using a higher API gravity to define black oil,

such as 45 or 50o 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 criteria for defining black oil, which were obtained directly

from widely recognized definitions of black oil and volatile oil
2-23

that are 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 made any

changes to the definition of black oil in response to these

comments.

Comment: Commenters IV-D-01 and IV-D-29 were concerned that

the exemption criteria would exempt facilities with significant

emissions. Commenter IV-D-01 requested that the EPA delete the

provision exempting black oil facilities from the requirements of

the subpart [§63.760(e)]. According to the commenter, most oil

and gas production facilities in Louisiana would probably be

exempt from the subpart. Furthermore, the commenter stated that

oil with an API gravity of 40 degrees is light crude and is

almost condensate. The commenter also stated that oil with a GOR

of 1,750 scf/bbl would be expected to result in high gas

production.

Commenter IV-D-29 supported lowering the black oil

applicability thresholds from a gas-to-oil ratio (GOR) less than

1,750 scf/bbl and an API gravity less than 40o to a GOR of less

than 1,250 scf/bbl and an API gravity less than 27 or 28o. The

commenter was concerned that the proposed applicability

thresholds for black oil would exempt nearly all tank batteries

in Santa Barbara County, California (diesel fuel has an API

gravity of 38o).

Response: Based on an evaluation of the available

information, the EPA determined that there is a low potential for

HAP emissions from black oil in the oil and natural gas

production source category. The top 12 percent of facilities in

this subcategory were not controlled, and due to the low

emissions potential, it was determined to be not cost effective

to go beyond the MACT floor. Therefore, the EPA established an

exemption from regulatory requirements in subpart HH for those

facilities that exclusively handle black oil. 

Furthermore, based on the EPA's understanding of the

characteristics of black oil, there may be significant gas

production from facilities that exclusively handle black oil. 
2-24

However, this gas would primarily have a low moisture content,

and generally have a low potential for HAP emissions. Therefore,

the EPA believes that facilities that process, store or handle

black oil are not significant sources of HAP emissions and has

not made any changes to the black oil definition in response to

this comment. The EPA believes that the proposed applicability

cutoffs are appropriate.

Comment: Commenter IV-D-02 recommended that the EPA

eliminate the definition for black oil in subpart HH, and "define

oil for purposes of part 63 as liquid hydrocarbons as Mineral

Management Service (MMS) does (30 CFR §206.51)." The commenter

agreed with the proposal to exempt black oil facilities provided

the definition of black oil was correct. According to the

commenter, defining black oil, which is dependant on many

variables, makes subpart HH too complex, and makes enforcement

impossible. The commenter stated that the EPA's definition of

"black oil" is arbitrary and capricious, and "totally neglects

long established and technically supportable definitions of

condensate and oil." The commenter noted that the EPA did not

include a discussion on reservoir condition of the hydrocarbon. 

The commenter stated that although the EPA was correct in

dividing hydrocarbons into two categories (black oil and

condensate), industry and MMS divide hydrocarbons differently

into "oil" and "condensate." The commenter suggested that

imposing two conflicting definitions of condensate and oil will

result in unwarranted confusion within industry and the agency. 

The commenter felt that the EPA's approach to define "black oil"

as something different from "oil" is not technically correct and

is confusing.

Response: As stated in a previous response, the definition

of black oil was developed using industry-defined terms. The EPA

believes that the gas that evolves from black oil does not

contain significant amounts of HAP. Therefore, the distinction

between black oil and volatile oil is important. The commenter's

proposed oil definition does not distinguish between volatile oil

and black oil. Therefore the EPA believes that a black oil
2-25

definition based on the MMS definition of oil would exempt

sources with significant HAP emissions.

Comment: Commenter IV-D-16 recommended that §63.760(e) be

amended to allow for the production of 10 thousand cubic feet per

day (MCF/D) of casing head gas for facilities that are otherwise

subject to the black oil exemption. The commenter explained that

most oil production facilities that process "black oil" produce a

small amount of "casing-head gas." The commenter defined

"casing-head gas" as a gas dissolved in the oil that separates

from the oil as production occurs. According to the commenter,

the casing-head gas produced by a black oil facility is not

economically significant, but is a by-product of the oil

production process.

Response: Instead of specifying casing head gas as being

allowed, the EPA believes that any gas brought on site for fuel

or gas generated from black oil should be allowed at a black oil

facility. Therefore, §63.760(e)(1) states that for subpart HH,

"...a black oil facility that uses natural gas for fuel, or

generates gas from black oil..." is still exempt.

Glycol Dehydration Units

Comment: Several commenters referred to the flowrate and

benzene emission rate exemptions for glycol dehydration units. 

Commenter IV-D-07 requested guidance on determining the annual

average for dehydrator de minimis and recommended that the

guidance be provided in §63.772(b). Commenters IV-D-24 and

IV-D-35 supported the use of flowrate and benzene emission rate

exemptions as it focuses on higher emissions, and according to

commenter IV-D-35, triethylene glycol (TEG) units are usually

located only at area sources. Commenter IV-D-12 requested that

the EPA clarify the methods proposed for determining dehydrator

HAP emission-based applicability and that the EPA provide

examples to show how these methods should be applied. 

Response: In response to several comments the EPA has made

changes to final subparts HH and HHH to clarify the compliance

demonstration requirements (see section 2.14 for further

discussion). In addition, §§63.772(b) of final subpart HH and
2-26

63.1282(a) of final subpart HHH specify how the average natural

gas flowrate is to be calculated. The final rules specify that

emissions must be determined based on representative operations

and the EPA believes that the owner or operator should have

records for the representative operation of each glycol

dehydration unit. The EPA will be publishing implementation

guidance following promulgation of subparts HH and HHH.

Comment: Commenter IV-D-29 stated that they support the

following:

(1) lowering the natural gas applicability threshold for glycol

dehydration units from 85 thousand m3 to 42 thousand m3. 

The commenter stated that the EPA offered no real

justification for the selected applicability threshold,

(2) lowering the benzene emission applicability threshold for

glycol dehydration units from 0.9 ton per year to 0.5 ton

per year. The commenter stated that the potential health

effects of benzene exposure and the significance of total

HAP emissions from the source category justify this change,

(3) replacing "or" with "and" when discussing glycol dehydration

unit applicability thresholds. Thus, only those units that

meet both the natural gas throughput and benzene emission

rate would be exempted from the 95-percent control level,

and

(4) establishing control measures for those glycol dehydration

units that do meet all the applicability thresholds.

Response: The EPA evaluated several options in attempting

to establish applicability criteria for glycol dehydration units. 

These options included a series of throughput, benzene emission

rates, and the use of the term "or" or "and" within the

applicability criteria. Based on its evaluation and to exempt

those emission points with low HAP emissions, the EPA does not

believe that changing its applicability criteria for glycol

dehydration units is necessary. Furthermore, there was no

evidence available to the Administrator to suggest that sources

with flow rates less than 3 MMscf/d or benzene emissions less

than 1 tpy are controlled at the floor, and it was not cost

effective to go beyond the floor.
5

It should be noted that these criteria are not related to

the determination of PTE. Sources that meet these criteria are

not subject to the control requirements of subparts HH and HHH,

but are still subject the NESHAP. In a previous response, the

EPA has announced the addition of an applicability cutoff for

which production facilities and transmission and storage

facilities below this value would not be subject to the NESHAP.

2-27

Comment: Commenter IV-D-10 requested clarification of the

term "benzene emissions to the atmosphere," for the 1 tpy cutoff. 

The commenter requested that the term mean actual benzene

emissions.

Response: It was the EPA's intent to specify actual average

benzene emissions and has revised proposed §§63.764(e) and

63.1274(b) (now codified at §63.764(e)(1) of final subpart HH and

§63.1274(d)(1) of final subpart HHH) to clarify that actual

average benzene emissions must be calculated for the 1-tpy

exemption.

Comment: Commenter IV-D-05 stated that, as proposed, the

regulations would exempt a glycol unit that processes less than

3 MMscf/d on an annual average, but is permitted to process more

than 3 MMscf/d annually. The commenter stated that this would

mean that PTE is not a factor as it historically has been in

determining affected units.

Response: The EPA proposed this applicability criteria to

exempt those glycol dehydration units for which the MACT floor

was identified to be no control. These glycol dehydration units

are not exempt from the subpart, but are exempt from the control

requirements of subparts HH and HHH.5 However, records of this

actual average throughput level (or the other applicability

criteria) must be documented and maintained annually to remain

exempted from the control requirements. 

The EPA has knowledge of facilities that operate their

glycol dehydration units above their nameplate capacity. 

Therefore, maintaining records of design capacity would not

ensure operation below the throughput cutoffs. Therefore,

§§63.774(d)(1) and 63.1284(d)(1) of the final rules specify that
2-28

actual annual average natural gas throughput must be maintained,

not the design capacity. Similarly, the final rules contain

criteria for documenting actual average benzene emissions

[codified at §§63.774(d)(2) and 63.1284(d)(2)].

Comment: Commenters IV-D-07 and IV-D-31 requested that the

EPA make provisions in the PTE determination for fluctuations in

water content and gas composition without having to sample the

gas stream frequently.

Response: It is the EPA's understanding that, based on

available information from the production industry, water content

and gas composition remain relatively constant if the source of

the input streams (such as reservoirs) does not change. However,

although dramatic fluctuations in water content and gas

compositions may occur in the transmission and storage industry,

it is believed that they would be over a short period. 

Furthermore, since PTE is a worst case calculation, the EPA does

not believe that frequent sampling would be required. However,

sampling would be required if the source of the input stream

changed. Therefore, the EPA has not modified subparts HH and HHH

in response to these comments.

Storage Vessels with the Potential for Flash Emissions

Comment: Commenter IV-D-03 requested that the proposed

storage tank exemption/control criteria be based on "credible

engineering test methods supported by fundamental principles of

fluid phase behavior." The commenter provided a Society of

Petroleum Engineers journal article entitled Test Method for

"Actual" True Vapor Pressure of Crude Oils. The article

presented data for flash gas emissions from black oil. According

to the article, a 35o API oil with a GOR of 13.4 scf/bbl had the

flash gas emission potential to exceed benzene, toluene, ethyl

benzene, xylene (BTEX) rates of 10 tpy with less than 5,000

bbl/day. The commenter noted that this oil would have been

exempted from the control requirements. The commenter further

noted that the DOE has degassed this oil to prevent such high

emissions.
2-29

Commenter IV-G-01 suggested that breathing, working, and

flashing losses from crude oil storage tanks are "significant"

when storage tanks have gas to oil ratios and API gravities less

than the minimums specified in subpart HH. The commenter

provided an example calculation of tank emissions to show how HAP

emissions from a crude oil storage tank could exceed 5 tons per

year [and exceed 16 tons per year of total reactive organic

compounds (ROC)]. The commenter was concerned that subpart HH,

as currently written, may not reflect the maximum degree of

reduction of HAP emissions for oil and gas production sources. 

Response: The criteria of an API gravity equal to or

greater than 40 degrees and 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. 

The EPA's analysis of storage vessels that contain hydrocarbon

liquids that have API gravity and initial producing GOR higher

than these criteria indicate the potential for significant flash

emissions.

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 "The Administrator

may distinguish among classes, types, and sizes of sources within

a category or subcategory in establishing such standards. . . ." 

In addition, 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 a previous response, 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
2-30

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.

Comment: Commenter IV-D-03 provided an example, developed

at the Strategic Petroleum Reserve, of a condensate with a GOR

greater than 20,000 standard cubic feet per barrel (scf/bbl) and

a 45o API gravity. The condensate was analyzed using the

EquiVapTM method. The condensate stream was determined to have

flash gas emissions potential due to true vapor pressures greater

than atmospheric. However, EquiVapTM also identified that after

the liquid was further stabilized by the flash tank, no flash gas

emissions were generated because the liquid had a true vapor

pressure less than atmospheric. According to the commenter, the

"arbitrary exemption/controls criteria would have required costly

recovery and incineration of nonexistent flash gases from this

stream even after it had been properly stabilized by the upstream

flash tank."

Response: 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 nonexempted 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. 

Comment: Commenter IV-G-01 requested guidance on how GOR

should be measured.

Response: The final subpart HH requires the owner or

operator to determine the initial producing GOR for the

definition of black oil and stock tank GOR for the definition of

storage vessels with the potential for flash emissions. As

stated in a previous response, this distinction is important
6

Reference 2.

2-31

because GOR changes with reservoir pressure. The EPA believes

that requiring a GOR measurement at the stock tank will ensure

that fluids with higher gas content (i.e., a greater potential

for flash emissions) will be subject to the control requirements.

In addition, the EPA has added a definition for initial

producing GOR to subpart HH as follows:

Initial producing GOR means the producing standard

cubic feet of gas per stock tank barrel at the time

that the reservoir pressure is above the bubblepoint

pressure (or dewpoint pressure for a gas).

The ratio of gas to oil should be constant until the bubblepoint

or dewpoint is reached in the reservoir.6

 There are various

methods within the industry available for measuring the GOR but

there is not an approved EPA method. Although the EPA does not

specify the method for subpart HH, the method used by the owner

or operator must achieve a determination of the standard cubic

feet of gas per stock tank barrel (scf/bbl) of the hydrocarbon

liquid.

Comment: Commenter IV-D-01 questioned the basis for

exempting storage vessels with an actual throughput less than 500

BPD [21,000 gallons per day (gal/day)] from control requirements

[§63.764(c)(2)], and requested that the EPA delete the provision. 

According to the commenter, 500 BPD is a substantial throughput

for the crude oil production in Louisiana. The commenter stated

that due to the storage vessel exemptions most facilities in

Louisiana would be exempt from this subpart.

Response: The data available to the EPA indicated that for

the class of storage vessels not considered to have the potential

for flash emissions (i.e., with API gravity less than 40o or a

GOR less than 1,750 scf/bbl) and with a hydrocarbon liquid

throughput less than 500 bpd, the MACT floor was no control and

it was not cost effective to go beyond the floor [Air Docket

A-94-04 numbers II-A-01 and II-D-50].

The EPA has added the throughput cutoff criterion to the

storage vessels with the potential for flash emissions definition
2-32

in final subpart HH. The final rule states that a storage vessel

with the potential for flash emissions is defined as a storage

vessel that contains an actual average hydrocarbon liquid with a

stock tank GOR equal to or greater than 1,750 scf/bbl and an API

gravity equal to or greater than 40 degrees, and a hydrocarbon

liquid throughput equal to or greater than 500 bpd. 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 §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 potential-to-emit (PTE)

calculation for determining major source status.

Comment: Commenters IV-D-04, IV-D-22, IV-D-34, and IV-D-35

requested that the EPA clarify the averaging period for the

500-BPD exemption criterion for storage tanks. Commenter IV-D-04

assumed that it was meant to be an annual daily average basis. 

Commenter IV-D-35 suggested using a five-year rolling average

based on maximum actual tank throughput. Commenter IV-D-34

requested that the storage tank throughput be based on an annual

average. The commenter also suggested that the calculation of

the 500-BPD threshold for storage tanks be based on a method

similar to that proposed for glycol dehydration unit flow rates

in §63.772(b)(1). Commenter IV-D-22 stated that there is no

discussion in subpart HH or the preamble of how to determine

applicability to the 500-BPD threshold for storage vessels. The

commenter recommended that the EPA allow either monitoring of the

flowrate, or other documentation (e.g., sales records) of the

storage vessel flowrate, and that calculation of the 500 BPD

limit be based on an annual average.

Response: As stated in a previous response, the 500-bpd

throughput has been added to the definition of storage vessels

with the potential for flash emissions. Thus, storage vessels

that do not meet this definition are exempt from subpart HH. 

Therefore, the EPA believes that establishing recordkeeping and

reporting requirements for these units would be inappropriate.
2-33

However, §63.10(b)(3) contains recordkeeping requirements

for applicability determination. Therefore, owners and operators

with storage vessels that are not subject to subpart HH would be

required under this section to maintain records of the

applicability determination for these storage vessels.

Comment: Commenter IV-D-07 requested that the EPA clarify

whether the regulation applies to the case where a tank battery

has an average throughput less than 500 bbl/tank but a total

throughput of greater than 500 bbl total.

Response: The throughput applicability criteria for storage

vessels with the potential for flash emissions in final subpart

HH applies to each storage vessel. Thus, a tank battery with a

total actual throughput of more than 500 BPD that consists of

several storage vessels, none of which has an actual average

annual throughput equal to or greater than 500 BPD would not be

subject to subpart HH, provided the GOR and API gravity criteria

are met. Therefore, the EPA has not modified subpart HH in

response to this comment.

Comment: Commenter IV-D-16 recommended that the EPA allow

tanks with a specified percent HAP to be excluded from subpart

HH. The commenter suggested that this would prevent a tank at a

major source, with low HAP contents in the liquid, from being

covered. According to the commenter, controls would not be

effective since HAP emissions would be low due to the low HAP

content in the liquid.

Response: The EPA has established that facilities that

process, store or transfer black oil have a low potential for HAP

emissions and are exempt from control requirements under subpart

HH. The EPA selected the criteria for defining storage vessels

with the potential for flash emissions using parameters that are

easily determined by the industry. Therefore, the EPA does not

believe that specifying a percent HAP content for hydrocarbon

liquids in subpart HH is necessary. Based on the EPA's knowledge

of the industry, the black oil exemption, by itself, exempts

approximately 85 percent of all tank batteries according to

industry data.
2-34

Comment: Commenters IV-D-07 and IV-D-24 stated that they

support exempting storage tanks that have the potential for flash

emissions and a hydrocarbon throughput less than 500 BPD. 

However, the commenter IV-D-07 requested an exception for

emergencies. Commenter IV-D-24 stated that the 500-BPD exemption

avoids imposing costly controls on the smallest sources.

Response: Through the startup/shutdown/malfunction

provisions in subpart HH, the EPA has attempted to address those

emergencies that may be encountered by industry. Furthermore,

the throughput exemption is based on an annual average, which

should account for daily fluctuations in throughput. Thus, the

EPA does not believe that an additional exemption is necessary in

subpart HH.

Comment: Commenter IV-G-12 stated that subpart HH is

lacking in that it does not distinguish between flashing and

evaporation. According to the commenter, this lack of

specificity could lead to confusion among sources and regulators

concerning which vessels/substances are covered by the proposed

rule. The commenter suggested that subpart HH be clarified to

specify a temperature/phase relationship or maximum vapor

pressure, as well as specifying the source and HAP content of the

liquid stream that is being stored. The commenter presented

examples. The commenter also stated that as an alternative the

EPA could define the term "flashing" in thermodynamic terms

(i.e., the change of state between liquid and vapor phases that

is not caused by the addition of thermal energy). The commenter

was interested in exempting produced water from a production

facility as well as lubricating oils, fuels, or other similar

fluids.

Response: Temperature and vapor pressure are very dependant

on stream composition. This variability makes it very difficult

to establish boundary conditions for the types of hydrocarbon

liquids processed in this industry. Furthermore, the EPA

believes that API gravity and GOR are values that are well

understood by the industry, and are usually readily available. 

The EPA does not believe that specifying a percent HAP content or
2-35

maximum vapor pressure for hydrocarbon liquids in subpart HH is

necessary. However, to clarify the term flash emissions, the EPA

has added the following language to the definition of storage

vessels with the potential for flash emissions that states "Flash

emissions occur when dissolved hydrocarbons in the fluid evolve

from solution when the fluid pressure is reduced and is not

caused by the addition of thermal energy."

Comment: Commenter IV-G-01 was concerned that HAP and

reactive organic compounds (ROC) emissions from storage vessels

with the potential for flash emissions may be significant with a

throughput less than 500 BPD. The commenter provided an example

calculation for a storage tank with a throughput of 250 BPD,

showing emissions from breathing, working and flashing losses. 

The example presented uncontrolled ROC emissions of 4.06 tpy and

controlled ROC emissions of 0.20 tpy. Uncontrolled HAP emissions

(including benzene, hexane, and 2,2,4-trimethylpentane) were

estimated to be 1.31 tpy (uncontrolled) and 0.07 tpy

(controlled).

Response: Based on the EPA's analysis, the storage vessel

applicability cutoffs of hydrocarbon liquid throughput of 500

bpd, a GOR less than 1,750 scf/bbl, and an API gravity less than

40o, the storage vessels with significant HAP emissions will be

controlled under this regulation. The example provided by the

commenter did not show total HAP emissions greater than the major

source thresholds of 10 tpy for individual HAP (the highest HAP

emissions were estimated to be 0.69 tons of hexane per year,

uncontrolled) or 25 tpy for any combination of HAP (total ROC

emissions were estimated to be 4 tpy, uncontrolled). Therefore,

since these emissions are well below the major source thresholds,

the EPA maintains that the 500-BPD cutoff is reasonable, and has

not changed the definition of storage vessels with the potential

for flash emissions.

Other Exemptions

Comment: Commenter IV-D-01 questioned the basis for

exempting reciprocating compressors in wet gas service from the

compressor control requirements of §61.242-3, and requested that
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the EPA delete the provision. According to the commenter, if

there was a leak, HAP released from a compressor in wet gas

service would be higher than that released from a compressor in

dry gas service, since the concentration of HAP is much higher in

wet gas.

Response: The exemption for reciprocating compressor in wet

gas service is consistent with 40 CFR subpart KKK, the Onshore

Natural Gas Processing Plant New Source Performance Standards

(NSPS). Therefore, the EPA has not removed this exemption from

subpart HH.

2.1.3 Other Applicability Issues

Comment: Commenter IV-D-14 stated that many oil and gas

production facilities are located in remote areas and do not have

a substantive impact on human populations. The commenter asked

what the underlying basis was behind the application of MACT

requirements to HAP sources located in remote areas, whether the

CAA allowed for remote facilities to be exempted from MACT

standards, and whether the EPA considered this in its rulemaking.

Response: The EPA does not have discretion in setting

standards for major sources of HAP emissions, which must be

implemented nationwide. Therefore, major sources located in

remote areas must still comply with MACT.

Comment: Commenter IV-D-16 was concerned that the

applicability section could be interpreted to mean that refinery

Natural Gas Liquid (NGL) plants could be brought into coverage

since they are at a refinery and at a major source. The

commenter requested that a specific exemption be added to §63.760

for NGL Plants at refineries, to make it clear that it is not the

intent of the regulation to cover refinery NGL Plants. According

to the commenter, the rationale behind this exemption would be

that NGL plants were not considered when the MACT floor was set

and that these plants already have controls put on them by other

regulations (e.g., SIP VOC regulations), therefore no

environmental purpose would be served by drawing them into

subpart HH.
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Commenter IV-D-16 was also concerned that the applicability

language could be misinterpreted to mean that existing major

sources that have a single or very few gas wells collocated with

the facility would be included. The commenter explained that a

few wells have been drilled and are producing at existing major

sources. According to the commenter, these plants should not be

subjected to coverage by subpart HH merely because they are major

sources for their primary activities and happen to have a single

or a very few gas or oil wells on-site. The commenter

recommended that the EPA exempt these facilities by making it

clear that subpart HH applies only to oil and natural gas

facilities that are major sources by themselves.

Response: The CAA requires the EPA to regulate major HAP

sources. A major HAP source is defined 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. . . . " This means that the EPA is

obligated to consider the whole site when determining if a source

is major and to regulate co-located emission sources (e.g.,

production wells), when applicable. It should be noted that

§63.760(d) states that if affected sources (glycol dehydration

units, tank batteries, and ancillary equipment located at natural

gas plants) are not present at a facility, there are no

requirements under subpart HH.

Comment: Commenters IV-D-16 and IV-D-22 were concerned that

proposed §63.760(b)(1)(iii) could be misinterpreted. The

commenters recommended that §63.760(b) should be modified to

clarify that only ancillary equipment located at natural gas

plants are to be considered an affected source. Commenter

IV-D-16 suggested that the EPA's intent was to include ancillary

equipment as an affected source for gas plants in the preamble

(63 FR 6295 and 6304). Commenter IV-D-22 suggested that the

phrase "located at natural gas processing plants" be added to

§§63.760(b)(1)(iii) and (iv).

Response: To clarify the applicability of subpart HH to

ancillary equipment, the EPA agrees with the commenters that
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additional language is necessary, and will add the phrase

"located at natural gas processing plants" to proposed

§63.760(b)(1)(iii) and (iv) [now codified at §§63.760(b)(3) and

(4) of final subpart HH].

Comment: Commenter IV-D-16 stated that the line between

subpart HH and subpart HHH needs to be clarified so the same

sources will not be covered by both rules.

Commenter IV-G-12 stated that they operate gas gathering

systems that accept gas from third party wells at which no

processing or treatment occurs. The commenter explained that

this gas is often gathered and brought to a central compressor

station where it is dehydrated and compressed and transferred to

a transmission pipeline. Although it seems unlikely that a

regulatory agency would try to aggregate emissions from the

gathering and production operations, the commenter suggested that

situations such as these be clarified in the final subpart HHH.

Commenter IV-D-21 cited two major problems with the EPA's

approach to defining the scope of the source categories. First,

the commenter suggested that subpart HHH lacks a clear definition

that distinguishes natural gas transmission and storage

facilities from natural gas production facilities. According to

the commenter, subpart HH states that the natural gas

transmission and storage source category begins at the point

where natural gas enters the natural gas transmission and storage

source category, but does not define this term. Additionally,

subpart HHH does not define the term "transport or store natural

gas." Therefore, the commenter was concerned that the regulated

entity would be required to draw guidance from the separate

definitions for "natural gas transmission" and "facility"

operating in subpart HHH. However, according to the commenter,

these two definitions provide contradictory guidance. For

example, the commenter interpreted the term "natural gas

transmission" to mean that the transmission and storage source

category would begin only when the natural gas first enters the

pipeline and the source category would not include any
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processing, either before or after initial entry into the

pipeline. According to the commenter, this interpretation is

supported by the definition of natural gas transmission by

recognizing that processing can occur in the transmission and

storage source category. The commenter recommended that the

final rule include an express delineation of the source

categories so the regulated community does not have to piece

together the delineation from various provisions throughout

subpart HHH.

According to the commenter, the second problem with subpart

HHH is that it fails to acknowledge that natural gas transmission

and storage facilities commonly process natural gas, both before

and after introduction of natural gas into the main transmission

line. The commenter cited the following examples of processing

that are integral to natural gas transmission activities by

minimizing the formation of hydrates: dehydration, removal of

CO2, and extraction of natural gas liquids. The commenter

suggested that this interpretation of the definition of facility

is also inconsistent with the BID, which notes that processing is

included in the transmission and storage source category. The

commenter further noted that processing occurs throughout the

pipeline, the location of which is determined by such factors as

gas quality and geographic location. The commenter requested

that subpart HHH recognize the fact that processing occurs as

part of transmission of natural gas.

To address the apparent lack of delineation between the

production and transmission categories, the commenter recommended

that a distinction between the two categories could be defined by

reference to the point at which that transfer to the transmission

company occurs. The commenter stated that processing operations

that occur prior to the transfer point would fall within the gas

production category, and those performed by the transmission

company after the transfer would fall in the transmission and

storage source category. According to the commenter, the BID

states that natural gas is typically transferred at a meter

station, but may occur at other points. The commenter stated
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that dehydrators operated by the transmission company after the

transfer point would fall within the transmission and storage

source category regardless of whether the dehydrators are located

before or along the main transmission line.

Response: The natural gas transmission and storage

definitions in subpart HHH were developed in consultation with

natural gas transmission and storage stakeholders. The EPA

believes that the definitions in subparts HH and HHH delineate

the boundaries of the oil and natural gas production and natural

gas transmission and storage source categories. The key points

in this delineation are (1) the point of custody transfer, which

is a commonly understood definition within industry, and (2) the

natural gas processing plant, which is a clearly defined facility

within the production source category. Based on these

discussions with industry, the EPA understood that there was only

one point of custody transfer indicating the point at which

natural gas entered the transmission pipeline. However, the EPA

has made some changes to more clearly define the boundary between

subparts HH and HHH.

The EPA believes that a compressor station located between a

well and a natural gas processing plant or between the well and

the point of custody transfer should be considered part of the

oil and natural gas production source category. Therefore, to

clarify this intent, the final subpart HH states that natural gas

enters the natural gas transmission and storage source category

after the natural gas processing plant, when present

[§63.760(a)]. 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. Subpart HHH

also states that compressor stations that transport natural gas

prior to the point of custody transfer, or to a natural gas

processing plant (if present) are considered part of the oil and

natural gas production source category [§63.1270(a)], and the

following definition of custody transfer has been added to

§63.1271:
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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.

The EPA has also made clarifying changes to the definition

of facility in subparts HH and HHH.
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2.2 DEFINITIONS

2.2.1 Facility

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. Commenter IV-D-35 agreed with the EPA's proposed

definition of facility. The following paragraphs present more

detailed comments on the definition of facility.

Comment: Commenter IV-D-02 was concerned that units, which

may include large sections of land and many leases and which are

under the control of a single operator, may be considered a

single facility. According to the commenter, units are created

when groups of leases are combined into a single entity, under

common control, and some States require the formation of units. 

The commenter stated that since the terms "site" and "lease" (as

contained in the definition of facility in §63.761) are not

defined in the Act or in subpart HH, it is unclear whether a unit

could be included within the term "lease" and whether a lease

retains it's identity when included in a unit.

Therefore, the commenter requested that the EPA define

facility to mean "the equipment at each individual well site and

each individual tank battery or each individual gas or oil

treating emplacement not located at the wellhead or tank

battery."

Commenters IV-D-05 and IV-D-14 were confused about whether

contiguous surface sites under common ownership would be

considered separate facilities. Commenter IV-D-05 requested that

the EPA modify the definition of facility in subpart HH to

exclude contiguous graded pad sites. Commenter IV-D-14 stated

that the term "surface site" could be interpreted as a single

concrete pad, a grouping of concrete pads in a contiguous area,

or a large graded area without any pads. According to the

commenter, subpart HH could be interpreted to mean that two or

more compressors on adjacent pads in a contiguous area are either

separate facilities or single facilities. The commenter noted

that this could also apply to several groupings of equipment used
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for different purposes but in the same graded area. The

commenter requested that the EPA clarify the definition of

facility to remove these uncertainties.

In addition, commenters IV-D-14 and IV-D-17 stated that

subpart HH does not address the issue of ownership or its effects

on the determination of what makes up a facility. The commenters

asked whether equipment under separate ownership at the same

surface site or adjacent surface sites could be considered a

single facility. Commenter IV-D-17 suggested that, for

clarification, a "facility" be defined to only include equipment

within the boundaries of an individual surface site that operate

under common ownership (e.g., central tank battery, graded pad

site, etc.).

Response: 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 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 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, be consistent with the intent

of the Act, and be 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
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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.

Comment: Commenter IV-D-05 suggested adding the term

"permitized area" to the definition of facility in subpart HH. 

The commenter stated that mineral leases give operators control

over large tracts of land. According to the commenter, adding

the term "permitized area" would clarify the definition of

facility where production equipment or equipment groupings on

different oil and gas leases are described.

Response: The EPA believes that adding the term "permitized

area" would add confusion to the definition of facility because

some facilities may not have established "permitized areas," and

different permitting authorities may define permitized areas

differently. The EPA has not made the requested changes to the

definition of facility in subpart HH.

Comment: Commenter IV-D-14 stated that subpart HH does not

address the role of the process in which a grouping of equipment

is engaged, in making the determination of what is a facility. 

The commenter explained that a graded area might contain a

compressor station, one or more tank batteries, and a separate
2-45

natural gas liquids plant. According to the commenter, each

grouping of equipment may be considered a separate facility by

the owner or operator, and each grouping may be found on separate

concrete pads in a contiguous area under common control. The

commenter asked whether these distinct operations would be

considered a single facility under subpart HH, and requested the

clarification of these issues.

Response: The definition of major source, as proposed in

subpart HH (§63.761), has the same meaning as in §63.2, except

that "emissions from processes, operations, or equipment that are

not part of the same facility, as defined in this section, shall

not be aggregated." A facility, as currently defined in §63.761,

includes equipment within the boundaries of an individual surface

site. The EPA believes that functionally-related equipment is

generally located at the same surface site. Thus, the EPA

believes that any grouping of equipment located on separate

concrete pads (i.e., separate surface sites) would not be

functionally-related; any grouping of equipment on separate

surface sites would be treated as a separate facility for which

emissions would not be aggregated. Furthermore, equipment

located on the same surface site may be a separate facility,

depending on where the point of custody transfer is within the

facility (e.g., the point at which natural gas enters a natural

gas processing plant is a point of custody transfer and thus the

natural gas processing plant would be considered a separate

facility located on the same surface site).

Comment: Commenter IV-D-16 recommended that the definition

of facility be modified to clarify that compressor engines are

not covered by subpart HH. The commenter noted that vents for

compressor engines are being covered by the Industrial Combustion

Coordinated Rulemaking (ICCR) and should not be covered under

subpart HH.

Response: Facilitywide HAP emissions after the point of

custody transfer must be included in the major source

determination. The EPA does not believe that engine vents from

compressors should be excluded from the definition of facility in
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subpart HH because HAP emissions from these units would not be

aggregated for major source determinations.

In addition, §63.760(b)(1) specifies the affected sources

for subpart HH. Therefore, the EPA believes that there should be

little confusion about which emission points are regulated under

subpart HH. Therefore, the EPA has not specifically excluded

engine vents for compressor engines from subpart HH requirements.

Comment: Commenters IV-D-08 and IV-D-22 recommended

clarification to the definition of facility in subpart HH to

include surface units and separate surface sites as tracts on

which multiple groupings of equipment may be located without

those separate groupings being designated as a "facility." In

addition, the commenters recommended that the definition specify

that connection by a road, a waterway, etc. does not cause two

separate groupings of equipment at different sites to be part of

the same facility. The commenters recommended the following

changes:

Facility means any grouping of equipment (1) where

hydrocarbon liquids are processed, upgraded, or

stored prior to the point of custody transfer, or

(2) where natural gas is processed, upgraded, or

stored prior to entering the natural gas

transmission source category. 

For the purpose of a major source determination,

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. 

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, walkway,

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, graded pad sites, and natural gas

processing plants.
2-47

Response: The EPA agrees with the commenter's

recommendations and has made the suggested changes to the

definition of facility in §63.761, except that the term "walkway"

has not been included in the definition. The EPA believes that

including this term would cause confusion for inspectors because

a walkway between pieces of equipment could become a part of the

boundary of a facility.

Comment: Commenter IV-D-29 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

commenter stated that several sources in Santa Barbara and

Ventura Counties that would otherwise be controlled would be

exempt from subpart HH under the proposed definition.

Response: 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. 

Comment: Commenters IV-D-06 and IV-D-31 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. Commenter IV-D-06 interpreted §63.1270(a) to mean

that the affected source runs all the way to the affected end

user, even if some local distribution company exists between the

natural gas transmission and storage source and the end user. 

The commenter remarked that according to the preamble, this was

not the EPA's intent. The commenter stated that the affected
7

This particular change is for an unrelated reason: roads

are not "equipment."

2-48

source is supposed to run all the way to the end user only if

there is no local distribution company. The commenter

recommended the following language to clarify §63.1270(a):

(a) This subpart applies to owners or operators

of natural gas transmission and storage facilities that

transport or store natural gas prior to entering the

pipeline to a local distribution company or (if there

is no local distribution company) to a final end user,

and that are major sources of hazardous air pollutant

(HAP) emissions.

The commenter also recommended changes to the definition of

facility to clarify this point.

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. A facility for this source category

typically is: A natural gas compressor station that

receives natural gas via pipeline, from an underground

natural gas storage operation, from a condensate tank

battery, or from a natural gas processing plant; or An

underground natural gas storage operation. The

emission points associated with these phases include,

but are not limited to, process vents. Processes that

may have vents included, 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 and is connected by ancillary equipment, such as

gas flow lines, roads, or power lines.7 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.

The commenter stated that this comment may also apply to subpart

HH.

Response: 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. 
2-49

Therefore, the EPA has added the phrase "if there is no local

distribution company" to §63.1270(a) and the definition of

facility in subpart HHH. The EPA also agrees that roads are not

equipment and has removed the term from the definition of

facility in §63.1271 of subpart HHH.

Comment: Commenters IV-D-07 and IV-D-31 stated that since

natural gas storage takes place in depleted gas wells, and

liquids are transferred for processing to the plant, the

definition of facility suggests that a natural gas storage

facility could qualify as a production facility. The commenters

stated that these terms must be clarified to avoid this

misunderstanding.

Response: 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." A production well is defined in §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 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 would not qualify as a production facility. The EPA does

not believe that clarification to the definition of facility is

necessary in response to this comment. 

Comment: Commenter IV-D-07 stated that in the preamble, the

term "upgraded" is used concerning hydrocarbon liquids, but is

not defined and should not be included in subpart HH.

Response: The EPA agrees that clarification to the

definition of the term "upgraded" is necessary. Therefore, the

EPA has modified the definition of facility in subpart HH to

specify that "upgraded" means "the removal of impurities or

other constituents to meet contract specifications."

Comment: Commenter IV-D-14 requested that the EPA clarify

the term graded pad in subpart HH. According to the commenter,
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clarification of this term is critical in establishing the limits

of a given "facility."

Response: The term graded pad is a term that is commonly

used in the industry. However, this term is used in the

definition of surface site, and is not appropriate as an example

of a facility. Therefore, the EPA has removed this term from the

definition of facility.

Comment: In their supplemental comments (IV-G-23),

commenter IV-D-22 recommended that the EPA modify the definition

of facility to clarify that product loading rack equipment falls

within the EPA's definition of facility. The commenter

recommended the following changes:

Facility means any grouping of equipment (1) where

hydrocarbon liquids, natural gas or natural gas liquids

are processed, upgraded, or stored prior to a point of

custody transfer; or (2) where natural gas is

processed, upgraded, or stored prior to entering the

natural gas transmission source category.

Response: The EPA does not believe that the commenter's

recommendations are necessary. Natural gas liquids are defined

in §63.761 as hydrocarbon liquids. Therefore, they are already

covered in the definition of facility in subpart HH.

2.2.2 Other Comments on Definitions

Affected Source

Comment: Commenters IV-D-08 and IV-D-22 recommended the

following new definition for affected source, which is "important

to the successful implementation of subpart HH":

Affected source: For major sources, each emission

point located at a facility that meets the criteria

specified in paragraph (a) and listed in paragraphs

(b)(1)(i) through (b)(1)(iv) of Section 63.760; for

area sources, each TEG dehydration unit located at a

facility that meets the criteria specified in paragraph

(a) of Section 63.760.

Response: The EPA believes that the addition of the term

affected source to §63.761 is unnecessary since it is defined in

§63.760(b).

Ancillary Equipment
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Comment: Commenter IV-D-06 pointed out that subpart HH

provides no definition for the term product accumulator vessel. 

The commenter stated that they did not know, and did not think

the EPA knew, what a product accumulator vessel was. According

to the commenter, new terms from the hazardous organic NESHAP

(HON), "surge control vessel" and "bottoms receiver" have

definitions the commenter can understand. The commenter

recommended that the EPA use one or both terms in place of

product accumulator vessel, if appropriate, and that the term

product accumulator vessel be eliminated. 

Response: The EPA agrees with the commenter that

clarification to the definition of ancillary equipment is

necessary and has modified the definition as follows:

Ancillary equipment means any of the following

pieces of equipment: pumps, compressors, pressure

relief devices, sampling connection systems, open-ended

valves, or lines, valves, flanges, and other

connectors, or product accumulator vessels.

The term "compressors" was removed because they are listed

separately in the subpart HH.

Comment: Commenter IV-D-22 recommended the following

modification to the definition of ancillary equipment to clarify

that such equipment is subject to subpart HH only if it is

located at a natural gas processing plant:

Ancillary equipment means any of the following

pieces of equipment located at a natural gas processing

plant: pumps, compressors, pressure relief devices,

sampling connection systems, open-ended valves or

lines, valves, flanges and other connectors, or product

accumulator vessels.

Response: Section 63.769(a) states that the equipment leak

standards apply to ancillary equipment at natural gas processing

plants. The EPA believes that specifying that ancillary

equipment is located at natural gas processing plants within the

ancillary equipment definition would be redundant. The EPA has

not altered the definition of ancillary equipment in response to

this comment.

Black Oil
2-52

Comment: Commenter IV-D-22 recommended the following

modification to the definition of black oil in subpart HH to

clarify the point of measurement and averaging period for the

GOR:

Black oil means hydrocarbon (petroleum) liquid

with an annual average wellhead gas-to-oil ratio (GOR)

less than 50 cubic meters (1,750 cubic feet) per barrel

and an API gravity of less than 40 degrees for the

storage tank liquids.

Commenter IV-G-01 stated that the proposed definition of

black oil does not state where the GOR applies and should be

clarified. The commenter stated that it was not clear if the GOR

applies at the storage tank where flashing occurs or at the

subsurface reservoir.

Response: The EPA intends that the GOR should be measured

as the initial producing GOR, rather than the average wellhead

GOR. The EPA has added the phrase "initial producing" before GOR

to the definition of black oil. The EPA has also added the

following definition for initial producing GOR to §63.761.

Initial producing GOR means the producing standard

cubic feet (scf) of gas per stock tank barrel (bbl) at

the time that the reservoir pressure is above the

bubblepoint pressure (or dewpoint pressure for a gas).

Boiler

Comment: Commenter IV-D-06 recommended that the EPA amend

the proposed definition of boiler to include resource

conservation and recovery act (RCRA) industrial furnaces. The

commenter explained that this change is necessary to provide

those devices an exemption from performance testing. The

commenter stated that the EPA should use the definition of boiler

in §63.111 of subpart G of the HON, verbatim, as the definition

of boiler in subpart HHH. The commenter stated that this comment

also applies to subpart HH. The commenter suggested that an

alternative would be to add separate provisions for industrial

furnaces; however, the commenter noted that this would require

more extensive drafting. Since all the relevant cross-references

to RCRA regulations are the same for industrial furnaces as for
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boilers and the commenter stated that adding industrial furnaces

to the definition of a boiler would be easier.

Commenter IV-D-22 recommended the following modification to

the definition of boiler to be consistent with the ICCR:

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.

Response: The EPA is not aware of any oil and natural gas

production or natural gas transmission and storage facilities

that would have RCRA industrial furnaces. However, the EPA does

not see any reason to not incorporate the commenter's (IV-D-06)

suggested language. In addition, the EPA has modified the

definition of boiler in subparts HH and HHH to be consistent with

the ICCR. The following definition of boiler has been added to

§§63.761 and 63.1271:

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

Comment: Commenter IV-D-06 requested that the EPA clarify

that closed-vent systems vent emissions to control devices and 

not to a process. The commenter explained that process piping

routes emissions to (or from or within) a process. The commenter

further explained that process piping may have equipment subject

to equipment leak monitoring requirements that should not be

subject to closed-vent system monitoring requirements. 

Therefore, the commenter suggested that the EPA make the

following changes to subparts HH and HHH:

(1) Revise the definition of closed-vent system in §63.1271 as

shown:

Closed-vent system means a system that is not open

to the atmosphere and is composed of piping, ductwork,

connections, and if necessary, flow inducing devices

that transport gas or vapor from an emission point to a

control device or back into the process. If gas or

vapor from regulated equipment is routed to a process

(e.g., to a fuel gas system), the process conveyance
8

This specific change is unrelated, but important. Subpart

HHH is not a VOC rule; it is a HAP rule. Additionally, the way

the proposed definition was worded, nothing could be a control

device unless it controlled both HAP and VOC. In other words, if

a device to control only HAP was installed, that device could not

be a control device because it is not also controlling VOC. Such

a result would be nonsensical, but it would appear to be

compelled by the literal wording of the proposed definition. By

eliminating the words "and volatile organic compound (VOC)" from

the definition, the EPA can resolve that difficulty.

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system shall not be considered a closed vent system and

is not subject to closed vent system standards.

(2) Revise the definition of control device as shown:

Control device means any equipment used for

recovering or oxidizing hazardous air pollutant (HAP)

and volatile organic compound (VOC)8 vapors. Such

equipment includes, but is not limited to, absorbers,

carbon adsorbers, condensers, incinerators, flares,

boilers, and process heaters. For the purposes of this

subpart, if gas or vapor from regulated equipment is

used, reused, returned back to the process, or sold,

then the recovery system used, including piping,

connections, and flow inducing devices, is not

considered to be control devices or closed-vent

systems.

(3) Revise §63.1275(c)(1) as shown:

(1) The owner or operator shall control air

emissions by connecting the process vent to a process

natural gas line through a closed-vent system designed

and operated in accordance with the requirement of

section 63.1281(c) and (d).

Response: The definitions of closed vent system and control

device and §63.1275(c)(1) of subpart HHH, and §63.765(c)(1) of

subpart HH, have been revised as follows, to clarify that

closed-vent systems vent emissions to control devices and not to

a process:

Closed-vent system means a system that is not open

to the atmosphere and is composed of piping, ductwork,

connections, and if necessary, flow inducing devices

that transport gas or vapor from an emission point to a

one or more control devices or back into the process. If gas or vapor from regulated equipment is routed to a

process (e.g., to a fuel gas system), the process

conveyance system shall not be considered a closed-vent

system and is not subject to closed-vent system

standards.
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Control device means any equipment used for

recovering or oxidizing hazardous air pollutant

(HAP) or and volatile organic compound (VOC)

vapors. Such equipment includes, but is not

limited to, absorbers, carbon adsorbers,

condensers, incinerators, flares, boilers, and

process heaters. For the purposes of this

subpart, if gas or vapor from regulated equipment

is used, reused (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.

Regarding the removal of "volatile organic compounds" from

the definition of control device, the EPA does not believe that

including VOC suggests that the Agency is regulating VOC. 

Compressor Station

Comment: Commenter IV-D-06 stated that the phrase "supplies

energy" in the definition of compressor station is vague. 

According to the commenter, under a literal interpretation of

subpart HHH, a power plant would be a "compressor station"

because it "supplies energy" to run the compressors that move the

gas. The commenter contended that the EPA intended that

compressor stations would have compressors. The commenter

suggested the following language for clarification:

Compressor station means any permanent combination

of equipment compressors that supplies energy to move

natural gas at increased pressure from fields, in

transmission pipelines, or into storage.

The commenter stated that this comment may also apply to

subpart HH.

Response: In order to clarify the Agency's intent, the EPA

has modified definition of compressor station in subpart HHH as

suggested by the commenter.

Condensate

Comment: Commenter IV-D-22 recommended the following

modification to the definition of condensate in subpart HH to

specify what the standard conditions are:

Condensate means hydrocarbon liquid that condenses

because of changes in temperature, pressure, or both,
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and remains liquid at standard conditions of 14.7

pounds per square inch, absolute (psia) and 60oF.

Commenter IV-D-02 recommended that the EPA define condensate

as MMS does at 30 CFR §206.51 as follows:

Condensate is a mixture of liquid hydrocarbons

that result from condensation of petroleum hydrocarbons

existing initially in a gaseous phase in the

underground reservoir.

Response: The EPA agrees that the definition of condensate

needs to refer to liquids produced from natural gas. In

addition, the definition of standard conditions (68 oF and 29.92

in Hg) is provided in subpart A (§63.2). Therefore, the revised

definition of condensate is as follows:

Condensate means hydrocarbon liquid separated from

natural gas that condenses due to because of changes in

the temperature, pressure, or both, and remains liquid

at standard conditions, as specified in §63.2 of this

part.

Condenser

Comment: Commenter IV-D-05 recommended that the EPA add a

definition for the term condenser. The commenter stated that

many still column vents have been modified to add tubing to the

normal exhaust port. According to the commenter, if an exhaust

experiences a temperature decrease because of a modification,

then any amount of tubing or apparatus added to decrease the

temperature could be classified as a condenser.

Response: The EPA does not agree that a definition of

condenser is necessary. It was not the EPA's intent to allow the

kind of scenario described by the commenter as a control

technology.

Continuous Seal

Comment: Commenter IV-D-06 interpreted the definition of

continuous seal to require a single-piece seal. According to the

commenter, some seals, consisting of more than one piece, make a

continuous seal. The commenter recommended that the EPA use

language similar to that used in the HON, which allows for seals

consisting of more than a single piece, for subpart HH.
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Response: The term continuous seal is not used in subpart HH

and has been removed from §63.761. In addition, the term fill or

filling is not used in subpart HH and has also been deleted.

Custody Transfer

Comment: Commenter IV-D-05 recommended that the term

custody transfer in subpart HH be clarified to account for the

case where a gas processing plant is incorporated within an oil

and gas production facility to process the gas further. The

commenter explained that in such cases, the gas does not leave

the pad site and does not change ownership.

Response: The EPA considers the point at which natural gas

enters a natural gas processing plant as a point of custody

transfer. Therefore, a natural gas processing plant is a

facility, despite whether or not the processing plant is

incorporated within the production facility. The EPA has not

made any changes to subpart HH in response to this comment.

Comment: Commenter IV-D-16 stated that the definition of

custody transfer in subpart HH is not consistent with the

definition of custody transfer in other rules. [Note: the

commenter did not provide examples of the other rules.] The

commenter recommended that the phrase "for this regulation" needs

to be added to clarify that this definition is only for subpart

HH, so no misunderstandings will occur. 

Response: The EPA has not made the commenter's recommended

changes to the definition of custody transfer. The definition of

custody transfer was derived from 40 CFR part 60, subpart Kb. 

Definitions in other rules would apply to those rules regardless

of how the EPA defines custody transfer in subpart HH, therefore

the commenter's clarification is unnecessary.

Comment: Commenter IV-D-16 recommended that the definition

of custody transfer needs to address that a custody transfer

still occurs when a subsidiary or different branch of the same

company "sells" or transfers natural gas to another branch of the

company.

Response: According to the proposed definition of custody

transfer, the scenario described by the commenter would be
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considered a custody transfer, if gas was transferred from

processing and/or treatment in the producing operations, from

storage vessels or automatic transfer facilities, to pipelines or

any other forms of transportation or if the gas was transported

to a natural gas processing plant. The scenario would not be

considered a point of custody transfer if the gas only changes

ownership within the company. Therefore, the EPA has not made

any changes in response to this comment. The EPA intends to

issue implementation guidance on applicability in the future.

Comment: According to commenter IV-D-22, the definition of

custody transfer in subpart HH does not need to include natural

gas since applicability for natural gas production is established

by the gas entry into the facility subject to the natural gas

transmission and storage source category. Therefore, the

commenter recommended the following modification to the

definition of custody transfer to refer only to hydrocarbon

liquids:

Custody transfer means, for purposes of this

subpart, the transfer of hydrocarbon liquids after

processing and/or treatment in the producing

operations, from storage vessels or automatic transfer

facilities to pipelines or any other forms of

transportation.

However, in their supplemental comments (IV-G-23), commenter

IV-D-22 requested that the EPA clarify that the point of custody

transfer is beyond such equipment as product loading racks so

that this equipment is covered by subpart HH. The commenter

stated that their position presented in their original comment

letter (i.e., to remove natural gas from the definition of

custody transfer) had changed. The commenter stated that they

believed that it would be prudent for the EPA to adopt the

following definition of custody transfer:

Custody transfer means the transfer of hydrocarbon

liquids or natural gas, after processing and/or

treatment in the production operations, from storage

vessels, 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 EPA considers the

point at which such liquids or natural gas are placed
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into pipelines or other forms of transportation to be a

point of custody transfer.

Response: The EPA agrees with the commenter. If the term

natural gas were removed from the definition of custody transfer,

the definition of associated equipment would be extended to the

end of the natural gas processing plant. During discussions with

industry, the EPA believes that it was clear that aggregating

emission points from natural gas processing plants was an

acceptable interpretation of section 112(n)(4). The EPA has also

made the recommended change to the definition of custody transfer

to incorporate loading rack equipment.

Equipment Leaks

Comment: Commenter IV-D-06 stated that the definition of

equipment leak is inconsistent with the definition of ancillary

equipment. For example, the commenter stated that product

accumulator vessels are not included under the definition of

equipment leak but they are included under the definition of

ancillary equipment. The commenter noted that other differences

between the two definitions are possible. According to the

commenter, §63.769 (equipment leak standards) applies to

"ancillary equipment" however, "that does not seem to work,"

especially for "ancillary equipment" that is not defined as

"equipment leaks." The commenter suggested that subpart HH

"could get by with" either a definition of "equipment leak" or a

definition of "ancillary equipment."

Response: The EPA has modified the definition of equipment

leaks as follows to remove inconsistencies between the

definitions of equipment leak and ancillary equipment:

Equipment leaks means emissions of hazardous air

pollutants from ancillary equipment (as defined in this

section) and compressors.

Federally enforceable 

Comment: Commenter IV-D-05 stated that the definition of

major source allows a unit to consider control devices when

making major source determinations. According to the commenter,

the preamble addresses this and makes it clear that the controls

must be federally enforceable. The commenter assumed that
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federally enforceable would apply if it were incorporated as a

condition of an operating permit that has gone through the

title V process (including the public comment period). If this

is not the correct interpretation, the commenter stated that the

term federally enforceable was vague and should be clarified.

Response: The commenter's interpretation was correct. The

definition of the term federally enforceable, in §63.2 of the

General Provisions, includes a list of federally enforceable

terms and conditions, which includes those contained in a title V

permit. The EPA believes that §63.2 is clear about what is

considered federally enforceable. Therefore, the EPA has not

incorporated a definition of federally enforceable that is

specific to subparts HH and HHH.

Field Natural Gas

Comment: Commenter IV-D-22 recommended deleting the

definition of field natural gas from subpart HH. The commenter

stated that the term was not sufficiently different from "natural

gas" to require a separate listing. 

Response: The term field natural gas is necessary to

distinguish between a natural gas production well and a natural

gas storage facility that uses a depleted well for storage. A

natural gas production well extracts natural gas that has not

been processed (i.e., field natural gas) and a natural gas

storage facility extracts natural gas that has been processed.

Therefore, the EPA has not removed the definition of field

natural gas from §63.761.

Flow Indicator

Comment: Commenter IV-D-06 recommended that the EPA clarify

that a flow indicator can include a device that shows the

position of a valve, rather than necessarily requiring a direct

reading of "flow." The commenter stated that some EPA inspectors

have said that a valve position indicator is not a flow indicator

because it does not directly detect "flow." The commenter

suggested that the literal language of some rules (before the

HON) might support this position. The commenter suggested that

the EPA use the current, amended definition of flow indicator
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from §63.111 of subpart G of the HON and use it in subpart HHH,

verbatim. The commenter stated that this comment also applies to

subpart HH.

Response: The EPA agrees that a flow indicator should show

valve position rather than directly reading the flow. Therefore,

the EPA has included the following definition of flow indicator

in final subparts HH and HHH:

Flow indicator means a device which that indicates

whether gas flow is present in a line or whether the

valve position would allow gas flow to be present in a

line.

Glycol Dehydration Unit

Comment: Commenter IV-D-06 stated that the definition of

glycol dehydration unit in subpart HHH has loopholes. According

to the commenter, a unit could be reconfigured so the natural gas

was not running counter currently to the glycol stream, meaning

the unit would not be considered a "glycol dehydration unit" and

would not be regulated. The commenter further explained that a

unit would not be considered a "glycol dehydration unit" and

would not be regulated if it were reconfigured to (1) regenerate

glycol by any method other than distillation, or (2) not recycle

glycol back to "the absorber." The commenter provided the

following language to address these loopholes.

Glycol dehydration unit means a device in which a

liquid glycol directly contacts a natural gas stream

(that is circulated counter current to the glycol flow)

and absorbs water in a contact tower or absorption

column (absorber). The glycol contacts and absorbs

water vapor and other gas stream constituents from the

natural gas and becomes "rich" glycol. This glycol is

then regenerated by distilling the water and other gas

stream constituents in the glycol dehydration unit

reboiler. The distilled or "lean" glycol is then

recycled back to the absorber.

The commenter stated that this comment may also apply to subpart

HH.

Commenter IV-D-22 recommended the following addition to the

definition of glycol dehydration unit to clarify the types of

units covered by subpart HH:
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Glycol dehydration unit means a device in which

liquid glycol (ethylene glycol, diethylene glycol, or

triethylene glycol) absorbent directly contacts a

natural gas stream (that is circulated counter current

to the glycol flow) and absorbs water vapor in a

contact tower or absorption column (absorber). . . . 

Response: The EPA agrees that the definition of glycol

dehydration unit in subparts HH and HHH has loopholes. 

Therefore, the EPA has modified the definition to remove any

possible loopholes and to add some examples of types of glycol

that may be used in the process. Final subparts HH and HHH

contain the following revised definition of glycol dehydration

unit:

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 (that

is circulated counter current to the glycol flow) and

absorbs water vapor in a contact tower or absorption

column (absorber). The glycol contacts and absorbs

water vapor and other gas stream constituents from the

natural gas and becomes "rich" glycol. This glycol is

then regenerated by distilling water and other gas

stream constituents in the glycol dehydration unit

reboiler. The distilled or "lean" glycol is then

recycled back to the absorber.

Hydrocarbon Liquid

Comment: Commenter IV-D-22 recommended the following

modification to the definition of hydrocarbon liquid to clarify

that produced water is not a hydrocarbon liquid:

Hydrocarbon liquid means any naturally occurring,

unrefined, petroleum liquid; produced water is not a

hydrocarbon liquid.

Response: The EPA has not modified the definition of

hydrocarbon liquid in response to this comment. The statement

that produced water is not a hydrocarbon liquid is contained in

the definition of produced water. The EPA believes that it would

be redundant to include it in the definition of hydrocarbon

liquid.

Hydrocarbon Throughput

Comment: Commenter IV-G-01 stated that hydrocarbon

throughput should be defined [for the storage tank applicability
2-63

criteria of 500 barrels per day (BPD)]. According to the

commenter, naturally occurring hydrocarbon consists of oil,

water, and gas.

Response: The EPA does not believe there is a need to add a

definition for hydrocarbon throughput. The storage tank

applicability criteria in §63.764(c)(2) is based on the "actual

throughput of hydrocarbon liquids." Furthermore, the term

hydrocarbon liquids is defined in §63.761.

In Volatile Organic HAP (VOHAP) Service

Comment: Commenters IV-D-06, IV-D-20, and IV-D-22 requested

clarification for the averaging period for the VOHAP

concentration trigger, for a stream to be subject to the

equipment leak standards. Commenter IV-D-06 asked whether the

threshold concentration of 10 percent organic HAP in the

definition of in VOHAP service in subpart HH means annual average

concentration, the normal concentration under standard operating

conditions, or the highest concentration ever encountered. The

commenter stated that if the 10 percent figure applies to the

highest concentration, it will make applicability and enforcement

difficult because the highest concentration will probably not be

present during inspections. Commenters IV-D-06, IV-D-20, and

IV-D-22 recommended an annual average, such as that in subpart H

of the HON or 40 CFR part 63, subpart CC. 

Response: The MACT floor for equipment leaks at natural gas

processing plants was determined to be at the level of control

required under the onshore natural gas processing plants NSPS (40

CFR part 60, subpart KKK). The control requirements of 40 CFR

part 60, subpart KKK are equivalent to those in 40 CFR part 61,

subpart V. Since subpart V is a HAP rule, the oil and natural

gas production NESHAP cross references subpart V. The

requirements in subpart V state that, for a piece of equipment to

be considered not in volatile HAP (VHAP) service, it must be

determined that the percent VHAP can be expected never to exceed

10 percent by weight. Therefore, the EPA has not modified the

averaging period for determination for in VOHAP service.
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However, to be consistent with subpart V, and to avoid

confusion between the two rules, the EPA has modified this

definition to refer to VHAP, rather than VOHAP. This change will

also affect several sections within subpart HH, including, the

definition of VOHAP (§63.761), the equipment leaks standards

(§63.769), and test methods and procedures (§63.772).

In Wet Gas Service

Comment: Commenter IV-D-01 stated that in wet gas service

is not defined in §§63.761 or 61.241. The commenter also stated

that it is not defined in either the NSPS or the hazardous

organic NESHAP (HON) equipment leak provisions.

Response: The EPA agrees that a definition of in wet gas

service is necessary. Therefore, the EPA has added the following

definition of in wet gas service to §63.761, based on the one

contained in subpart KKK:

In wet gas service means that a piece of equipment

contains or contacts the field gas before the

extraction of natural gas liquids.

Incinerator

Comment: Commenter IV-D-06 noted that the definition of

incinerator contains the wrong word. The commenter stated that

the last sentence mentions energy recovery sections that "permit"

the incoming vent stream or combustion air and it should say

"preheat." The commenter stated that this comment may also apply

to subpart HH.

Response: The definition of incinerator in subpart HHH has

been revised to change the word "permit" to "preheat." A

definition of incinerator was not included in subpart HH. 

Therefore, the same revised definition has been added to §63.761

of final subpart HH.

Natural Gas

Comment: Commenters IV-D-07 and IV-D-31 requested that the

EPA revise the definition of natural gas in §63.1271 to state

that the primary constituent of natural gas is methane, without

reference to any other components. Additionally, according to

the commenters, water vapor is essentially removed before
9

 National Emission Standards for Hazardous Air Pollutants

for Source Categories: Oil and Natural Gas Production and

Natural Gas Transmission and Storage - Background Information for

Proposed Standards. U.S. Environmental Protection Agency. 

Research Triangle Park, NC. Publication No. EPA-453/R-94-079a. 

April 1997.

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transmission. The commenters stated that it appears the

definition of natural gas used is more appropriate for production

gas than transmission and storage gas. 

Response: The EPA agrees that the definition of natural gas

is confusing. Therefore, the EPA has revised the definition of

natural gas in §§63.761 and 63.1271 based on the definition

contained in the Onshore Natural Gas Processing NSPS, 40 CFR part

60, subpart LLL (§60.641):

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

Comment: Commenter IV-D-22 recommended the following

modification to the definition of natural gas liquids in subpart

HH to distinguish liquid phase hydrocarbons from vapor phase

hydrocarbons:

Natural gas liquids (NGLs) means the liquid

hydrocarbons, such as ethane, propane, butane, pentane,

natural gasoline, and condensate that are extracted

from field gas.

Response: The EPA agrees with the commenter and has

modified the definition of natural gas liquids, as follows:

Natural gas liquids (NGLs) 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

Comment: Commenter IV-D-07 noted that the definition of a

natural gas processing plant in subpart HH is inconsistent with

the background information document (BID)9

. According to the

commenter, "extraction" not "separation and fractionation" is

described as occurring at a natural gas processing plant. The
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commenter stated that a definition of "extraction" or

"separation" should be included in the definition. As an

alternative, the commenter recommended that the EPA use the BID

description. The commenter also stated that the definitions of

"field natural gas" and "production well" are inadequate.

Commenter IV-D-11 requested that the EPA clarify the term

"extraction" as it is used in the definition of natural gas

processing plant in subpart HH. The commenter was concerned that

the term "extraction" could be misinterpreted to include simple

producing field separation of natural gas and liquids that occurs

absent of "processing." The commenter stated that the EPA's

discussion of its interpretation of the term "extraction" in the

proposal and background documents for the NSPS for Natural Gas

Processing Plants (subpart KKK) were a correct interpretation for

those activities that occur at a natural gas plant versus those

that occur at field production facilities. The commenter was

concerned that the State employees that interpret the rules for

compliance purposes are not always familiar with natural gas

processes. The commenter recommended that the EPA include a

definition of "extraction" similar to that in the NSPS preamble

in the final subpart HH. The commenter stated that if the EPA

does not include this definition in the final rule, the EPA

should clarify the intent of the term in the response to comments

in the final rule's preamble.

Response: The EPA does not believe that further

clarification is necessary. The EPA has had extensive discussions

with industry and trade associations during the development of

subpart HH related to the definitions of field natural gas and

production well, and developed these definitions based on this

information. Furthermore, the definition of natural gas

processing plant in §63.761 corresponds to the definition in

subpart KKK. 

Comment: Commenter IV-D-16 suggested that tighter language

or the addition of exclusionary language should be added to the

definition of natural gas processing plants to clarify that

subpart HH does not cover natural gas liquid (NGL) plants located
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at refineries. According to the commenter, as defined, NGL

plants at refineries which take liquid NGLs into the plant and

fractionate them into pure NGL streams would be included.

Response: It was not the EPA's intent to regulate NGL

plants at refineries under the provisions of subpart HH. 

However, the it was the EPA's intent that natural gas processing

plant mean any processing site engaged in both of the criteria

listed in the proposed definition. Therefore, the EPA has

modified the definition of natural gas processing plant as

follows:

Natural gas processing plant (gas plant) means any

processing site engaged in: (1) the extraction of

natural gas liquids from field gas, or (2) the

fractionation of mixed NGLs to natural gas products, or

a combination of both.

Comment: Commenter IV-D-22 recommended the following

modification to the definition of natural gas processing plant in

subpart HH to identify the gas plant according to its primary

activities and Standard Industrial Classification (SIC) or North

American Industry Classification System (NAICS) code:

Natural gas processing plant (gas plant) means any

processing site, engaged in the primary purpose of

which is (1) the extraction of natural gas liquids from

field gas, (2) the fractionation of natural gas liquids

to natural gas products, or both, and which is

classified in SIC Code 1321 (NAICS Code 211112). For

purposes of subpart HH, a gas plant is considered a

facility. A major source determination for a natural

gas processing plant will aggregate HAP emissions from

the facility, between the inlet scrubber and the plant

tailgate or other facility outlet boundary.

Response: The EPA has not made the recommended modification

to the definition of natural gas processing plant. The EPA does

not believe that including an SIC code in the definition of

natural gas processing plant is necessary. Furthermore, the EPA

does not believe that the commenters last two suggested sentences

(beginning with "For the purposes of subpart HH . . . ") are

necessary because the intent contained within these sentences is 

included in the definition of facility.

No Detectable Emissions
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Comment: Commenter IV-D-06 interpreted the definition of

"no detectable emissions" to require an instrument reading of

zero. The commenter stated that this is incorrect, as other

portions of subpart HHH require an instrument reading of 500

parts per million (ppm) or less for "no detectable emissions." 

The commenter provided the following language for revising the

definition of no detectable emissions in subpart HHH:

No detectable emissions means no escape of

hazardous air pollutants (HAP) from a device or system

to the atmosphere as determined by:

(1) Testing the device or system Instrumental

monitoring results in accordance with the requirements

of §63.1282(d); and

(2) No visible openings or defects in the device

or system such as rips, tears, or gaps.

The commenter stated that this comment may also apply to subpart

HH. 

Commenter IV-D-22 recommended the following alternative

definition for no detectable emissions in subpart HH to conform

with the NSPS (subpart KKK):

No detectable emissions means no escape of HAP

from a device or system to the atmosphere as determined

by: (1) Testing the devices or system in accordance

with §63.772(c) the arithmetic difference between the

maximum organic concentration indicated by the

instrument and the background level that is less than

10,000 parts per million by volume; and (2) No visible

openings or defects in the device or system such as

rips, tears, or gaps.

Response: The definition of no detectable emissions does

not require an instrument reading of zero. Therefore, to clarify

the definition of no detectable emissions in final subparts HH

and HHH, the EPA has revised the definition as follows:

No detectable emissions means no escape of HAP

from a device or system to the atmosphere as determined

by:

(1) Testing the device or systemInstrument

monitoring results in accordance with the requirements

of §63.1282(b) [§63.772(c) for subpart HH]; and

(2) The absence of visible openings or defects in

the device or system such as rips, tears, or gaps.

The EPA believes that restating the requirements of the Test

Methods and Procedures sections in subparts HH and HHH
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[§63.771(c) and §63.1282(d)] within the definition of no

detectable emissions is redundant. The EPA did not include these

requirements in the definition.

Process Heater

Comment: Commenter IV-D-22 recommended the following

modification to the definition of process heater in subpart HH to

conform with the ICCR:

Process heater means a device that transfers heat

liberated by burning fuel directly to process streams

or to heat transfer liquids other than water 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 unit (rather

than for steam generation).

Response: Since the definition proposed by the commenter is

reasonable, the EPA has modified the definition of process heater

in subparts HH and HHH, as follows:

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)that

transfers heat liberated by burning fuel directly to

process streams or to heat transfer liquids other than

water.

Process Unit

Comment: Commenter IV-G-12 noted that the definition of

natural gas processing plant in subpart HH is identical to that

contained in 40 CFR part 60, subpart KKK, but the definition of

process unit is not included. The commenter was concerned that

without this accompanying definition, subpart HH could be

interpreted ambiguously with respect to exactly what equipment

is, or is not subject to regulatory requirements. The commenter

suggested adding the definition of process unit from subpart KKK.

Response: The term process unit, as used in 40 CFR part 60,

subpart KKK, is necessary to determine the affected sources for

that rule. Since the affected sources in subpart HH are listed

in §63.760(b), the definition of process unit is not necessary.

Production Field Facilities
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Comment: Commenter IV-G-01 requested that the EPA clarify

whether outer continental shelf (OSC) platforms are considered

production field facilities.

Response: The determination about whether OCS platforms are

production field facilities is based on existing OCS regulations

and the EPA has not added clarifying language to subpart HH. 

Under the current definition, OCS platforms would be considered

production field facilities when in waters under EPA control as

designated by existing OCS regulations.

Startup and Shutdown

Comment: Commenter IV-D-06 suggested that the EPA have

specific definitions of startup and shutdown in subpart HHH. The

commenter remarked that the EPA's apparent use of the General

Provisions definition of startup and shutdown will not work. The

commenter stated that the definitions in the General Provisions

deal only with startups and shutdowns of a process and do not

deal with startups and shutdowns of control devices or monitoring

systems. The commenter was concerned that the startup, shutdown,

and malfunction plan for a facility would not be applicable for

reducing emissions during a control device or monitoring system

malfunctions. The commenter recommended that the EPA include

specific definitions of startup and shutdown in subpart HHH, and

that those definitions should include control devices and

monitoring systems. The commenter stated that this comment also

applies to subpart HH.

Response: The purpose of the startup, shutdown, and

malfunction plan, as defined in §63.6(e)(3) of the general

provisions (subpart A), is to "ensure that, at all times, owners

or operators operate and maintain affected sources, including

associated air pollution control devices, in a manner consistent

with good air pollution control practices for minimizing

emissions . . . " The EPA has added definitions for startup and

shutdown, based on the definitions found in §63.101 of subpart F,

to §§63.761 and 63.1271. It should be noted that the definitions

of startup and shutdown contained in subpart F do not contain

language referring to control devices or monitoring equipment.
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State Waters

Comment: Commenter IV-D-22 recommended adding the following

definition of state waters in subpart HH to clarify the scope of

coverage of offshore facilities:

State waters means those waters for which States

have been granted jurisdiction over offshore lands to a

distance of three nautical miles from their coasts by

the Submerged Lands Act [43 U.S.C. 1301, et seq.]. In

the case of waters offshore from Texas and from Florida

in the Gulf of Mexico, State waters are those waters

over offshore lands for which these two states have

jurisdiction to a distance of three marine leagues

[approximately 10.35 statute miles].

Response: The scope of coverage of OCS platforms is based

on existing OCS regulations. Therefore, the EPA did not add

clarifying language to subpart HH.

Storage vessel

Comment: Commenter IV-D-05 recommended that the EPA define

storage vessel. The commenter asked if a group of tanks at a

facility or each separate tank was considered a storage vessel. 

The commenter explained that in the case where two tanks process

900 BPD and share a common vent, applicability could be easily

avoided with by adding vents to each tank and dividing the flow

in half to be below the 500 BPD cutoff.

Response: According to §63.761, a storage vessel is defined

as "a tank or other vessel." Therefore, a group of tanks would

not be considered a storage vessel. Additionally, storage vessel

applicability is on a per vessel basis. In the scenario

described by the commenter, applicability would be based on

actual tank throughput despite vent configuration. Therefore,

the EPA has not made the suggested change.

Storage vessel with the potential for flash emissions

Comment: Commenter IV-D-08 recommended the following new

definition for flash gas in subpart HH:

Flash Gas: VOC emissions from depressurization of

crude oil or condensate when it is transferred from a

higher pressure to a lower pressure tank, reservoir, or

other container.
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Commenter IV-D-07 recommended that the EPA clarify the definition

of flash emissions. The commenter stated that at some

facilities, a small pressure drop exists between a separator and

a storage vessel, so flash emissions are low. The commenter

explained that many facilities dump separators straight into a

wet header system, and have no flash emissions, while other

facilities may only dump low-pressure separators to atmospheric

storage tanks. 

Response: The EPA believes that regulating storage vessels

based on tank contents rather than operation will prevent the

possibility of HAP emissions being emitted to the atmosphere via

flashing from uncontrolled tanks. The EPA has added the

following language to the definition of storage vessel with the

potential for flash emissions to clarify what is meant by flash

emissions:

. . .Flash emissions occur when dissolved hydrocarbons

in the fluid evolve from solution when the fluid

pressure is reduced.

Comment: Commenter IV-D-07 suggested that the EPA delete

the requirement for an API gravity of 40o and use the requirement

for hydrocarbon liquids with a GOR of 1,750 scf/bbl of condensate

in the definition of "flash emissions." The commenter stated

that flexibility is added to the definition since if the GOR

changes over time, it could be averaged over one year. The

commenter also suggested that the specific gravity for an API

gravity of 40o is 0.83 which, according to the commenter, seems

"excessively low."

Commenter IV-G-02 stated that controlling storage vessels

with the potential for flash emissions is an appropriate goal

(since most storage tank emissions in oil and gas production are

associated with flash emissions). The commenter explained

however, that using API gravity as a threshold for determining if

flash emissions occur is not appropriate, by itself, as a good

indication of flash potential. The commenter suggested that GOR

directly measures flash potential and is much more appropriate

for use as a control cutoff criterion. The commenter recommended
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that the EPA delete the API gravity criteria from the proposed

definition of "storage vessel with the potential for flash

emissions" in §63.761.

Response: The cutoffs included in the definition of storage

vessels with the potential for flash emissions are intended to

identify storage vessels that have the potential for flash

emissions. The EPA believes that both the API gravity and stock

tank GOR of a liquid are necessary to identify the hydrocarbon

liquids that the EPA believes to have the potential for flash

emissions. In addition, a throughput cutoff of 500 BPD per tank

was added to the definition because the EPA believes that flash

emissions are more likely with higher throughputs. Sections

63.760(a)(1)(iii) and 63.1270(a)(4) of the final rules state that

other parameters used to calculate emissions (such as API gravity

or GOR) must be the maximum for the period over which the maximum

natural gas or hydrocarbon liquid throughput is determined, and

must be based on highest measured values or annual averages. The

EPA has not altered the definition of storage vessel with the

potential for flash emissions based on this comment. 

Comment: Commenter IV-D-07 requested that the definition of

storage vessels with the potential for flash emissions clarify

how emission estimates and seasonal operation should be handled.

Response: Since the hydrocarbon liquid throughput cutoff is

based on actual throughput, seasonal fluctuations should not

affect applicability. The EPA has not supplied guidance on

emission estimations in the promulgated rule. The EPA intends to

publish guidance for emission estimations. 

Comment: Commenter IV-D-08 recommended the following

revisions to the definition for storage vessel with the potential

for flash emissions in subpart HH:

Storage vessel with the potential for flash

emissions means any storage vessel that contains a

hydrocarbon liquid with a wellhead-weighted average GOR

equal to or greater than 50 cubic meters (1,750 cubic

feet) per barrel or and an API gravity equal to or

greater than 40 degrees.
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Commenter IV-D-22 recommended the following modification to

the definition of storage vessel with the potential for flash

emissions in subpart HH, to clarify that the GOR is the annual

average wellhead GOR and to indicate the point of measurement:

Storage vessel with the potential for flash

emissions means any storage vessel that contains

hydrocarbon liquids with a GOR equal to or greater than

50 cubic meters (1,750 cubic feet) per barrel

determined as an annual weighted average of the wells

feeding the storage vessel or an API gravity equal to

or greater than 40 degrees measured at the storage

tank.

Response: The GOR is a measure of the amount of entrained

gas contained in a hydrocarbon liquid. Therefore, the higher the

GOR, the higher the potential for flash emissions. The EPA

believes that the GOR should be measured as close to the storage

vessel as possible, as the stock tank GOR, to obtain a realistic

value to determine flash emissions. The EPA has added the phrase

"stock tank" before GOR to the definition of storage vessel with

the potential for flash emissions.

In addition, 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 1,750 scf/bbl and an API

gravity equal to or greater than 40 degrees, and a hydrocarbon

liquid throughput equal to or greater than 500 bpd. 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 §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. 

Surface Site

Comment: Commenter IV-D-16 requested that the word

"platform" be removed from the definition of surface site in
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subpart HH. According to the commenter, when covered with the

definition of facility, the definition of surface site could be

misinterpreted to include offshore platforms. The commenter

stated that offshore platforms should not be covered by

section 112 since control of emissions offshore will not protect

the public as there is no public offshore.

Response: It is not the EPA's intent to exempt offshore

platforms. Therefore, the EPA has not removed the term platform

from the definition of surface site.

Comment: Commenter IV-D-22 recommended the following

modification to the definition of surface site in subpart HH to

clarify that individual surface sites connected by linear

installations (e.g., roads, waterways, etc.) are not part of the

same facility:

Surface site means the graded pad, gravel pad,

foundation, platform, or immediate physical location

upon which equipment is physically affixed. Individual

surface sites connected solely by a road, waterway,

walkway, power line, or pipeline shall not be

considered part of the same facility.

Response: The EPA agrees with the commenter and has

modified the definition of facility by adding language to clarify

that two or more surface sites connected by linear installations

are not part of the same facility. The EPA does not believe it

is necessary to add the same clarifying language to the

definition of surface site. However, the surface site definition

has been revised as follows to specify that graded pad sites and

gravel pad sites are considered surface sites:

Surface site means any combination of one or more

the graded pad sites, gravel pad sites, foundations,

platforms, or the immediate physical location upon

which equipment is physically affixed.

Temperature Monitoring Device

Comment: Commenters IV-D-08, IV-D-22, IV-G-02, and IV-G-12

recommended the following modification to the definition of 

temperature monitoring device in subpart HH to allow equipment

that uses the Fahrenheit scale, and to remove the accuracy

specifications:
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Temperature monitoring device means a unit of

equipment used to measure monitor temperature at any

point in a process in degrees F or C and having an

accuracy of +1 percent of the temperature being

monitored expressed in oC, or + oC, whichever is

greater.

Response: The EPA has modified the definition of

temperature monitoring device, as follows, to allow equipment

that uses the Fahrenheit scale and to clarify that the accuracy

requirements are the minimum allowed to ensure compliance. The

EPA believes that the accuracy requirements are necessary to

ensure that monitoring equipment is operating to demonstrate

ongoing compliance. However, the EPA has modified the level of

accuracy to allow the owner or operator more flexibility in

choosing a monitoring device.

Temperature monitoring device means an instrument

a unit of equipment used to monitor temperature and

having an minimum accuracy of +21 percent of the

temperature being monitored expressed in oC, or +2.50.5

oC, whichever is greater. The temperature monitoring

device may measure temperature in degrees Fahrenheit or

degrees Celsius, or both.

Underground Natural Gas Storage Facilities

Comment: Commenter IV-D-07 stated that the definition for

underground natural gas storage facilities is inconsistent with

the storage process. The commenter stated that the preamble

describes underground storage facilities as "typically extending

from the natural gas processing plant to the local distribution

company." According to the commenter, most storage facilities

recover gas from former production wells, separate the liquids in

high pressure separators, transfer liquids to a wet header system

that transports liquids to a gas processing plant (these liquids

are laden with natural gas), and dehydrates the natural gas

before transfer to the pipeline network.

Response: The preamble to the proposal describes natural

gas transmission and storage facilities as "typically extending

from the natural gas processing plant to the local distribution

company," and underground storage facilities as "subsurface

facilities that store natural gas that has been transferred from
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its original location for the primary purpose of load balancing." 

It is not the EPA's intent for the description to be all

inclusive of processes at a storage facility and believes that

the description of underground storage sufficiently covers the

storage process. Therefore the EPA has not made any changes to

the regulation in response to this comment.
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2.3 ASSOCIATED EQUIPMENT

Several commenters responded to the EPA's request for

comments on their interpretation of "associated equipment" in

section 112(n)(4) of the Act.

Comment: According to commenters IV-D-02, IV-D-04, IV-D-07,

IV-D-08, IV-D-19, IV-D-20, IV-D-22, IV-D-31, IV-D-33, IV-D-38,

IV-G-02, and IV-G-03, section 112(n)(4) mandates no aggregation

of emissions from individual sources at oil and gas production

fields. Commenters IV-D-04 and IV-D-31 stated that the CAA

provides a clear intent to not aggregate emissions from small

sources (e.g., exploration or production wells and their

associated equipment, compressor stations and other similar

units) in order to create major sources. Commenters IV-D-02,

IV-D-07, IV-D-19, IV-D-20, IV-D-33, and IV-D-38 stated that the

EPA exceeded its statutory authority under section 112(n)(4) in

its proposed definition of facility, by allowing for the

aggregation of emissions from glycol dehydration units and

storage vessels with the potential for flash emissions. The

commenters requested that the EPA be consistent with the CAA. 

According to commenter IV-D-20, the EPA did not create a

regulatory definition that is true to the statute.

Response: The EPA disagrees 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 emissions

points separated over large distances.
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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 or production well (with 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 and developed the proposed definition. The

commenters did not offer substantive new information to support

their claim that the EPA had exceeded its authority. The next

comment and response provide additional information regarding the

development of the definition of associated equipment.

Comment: Commenters IV-D-07, IV-D-19, IV-D-20, IV-D-33, and

IV-D-38 did not agree with the EPA's definition of associated

equipment, and contended that glycol dehydration units and

storage vessels with the potential for flash emissions should be

considered "associated equipment."

Although they did not support the EPA's proposed definition

of associated equipment, commenter IV-D-20 stated their support

for the EPA's efforts to control HAP that represent an adverse

impact to human health and the environment by focusing on the

sources that emit the most HAP from the oil and natural gas

production source category.

Commenters IV-D-19 and IV-D-20 were concerned that creating

exemptions from the terms of the statute would create a negative

precedent for this and future rules and, along with commenter

IV-D-38, requested that the EPA modify the definition of major

source and associated equipment to comply with the provisions of

CAA section 112(n)(4)(A).

Commenter IV-D-29 supported a more narrow definition of

"associated equipment" that also excludes glycol dehydration
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units and storage vessels with flash emissions. The commenter

was concerned that many potential major sources in Santa Barbara

and Ventura counties would be exempted under the broad definition

of associated equipment.

Although commenters IV-D-08, IV-D-22, IV-G-02, and IV-G-03

did not fully support the EPA's interpretation of "associated

equipment," they acknowledged that the proposal to limit the

aggregation of emissions to HAP from glycol dehydration units and

storage vessels with the potential for flash emissions was a

workable solution to the aggregation of all HAP sources. The

commenters suggested that the aggregation of dehydration units

and storage vessels with flash potential would result in the same

major source determination as aggregation of all potential

sources, but would reduce the burden on the facility operator. 

In addition, commenter IV-D-05 stated that the rationale and

conclusions used to clarify ancillary equipment for aggregating

emissions for a major source determination seemed appropriate.

[Note: The commenter mentioned "ancillary equipment" but most

likely meant "associated equipment," as the comment appears to be

directed toward associated equipment.] According to the

commenter, the EPA's decision to aggregate glycol units and

storage vessels with flash emissions will "give the rule some

degree of effectiveness." 

Response: 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.
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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. 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 evaluated several options. The Agency also sought and

received input from industry and other stakeholders.

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 emissions 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.
10 Conference Debates and Report. In: A Legislative History

of the Clean Air Act Amendments of 1990. U.S. Government

Printing Office. November 1993. P. 1238.

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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 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

history10 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
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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. 

Comment: Commenter IV-D-07 remarked that it is arbitrary to

include storage vessels in which treating and processing does not

take place as associated equipment, because these vessels have

the highest potential for flash emissions as compared to storage

vessels further downstream. 

Response: With regard to including, as associated

equipment, storage vessels in which no treating or processing

takes place, this statement in the preamble to the proposal

referred to an intermediate option that the EPA considered. 

Under this option, all equipment up to the point where initial

processing of an extracted hydrocarbon stream takes place would

be considered associated equipment. Thus, only the Christmas

tree and storage vessels in which no treating or separation takes

place would be considered associated equipment. However, this

option was rejected by the EPA as being a definition that was too

narrow.

The option selected by the EPA states that storage vessels

with the potential for flash emissions are not to be considered

associated equipment. Therefore, the EPA has focussed the
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standards (subpart HH) on those storage vessels with significant

emissions.

Comment: Commenter IV-G-01 requested that the EPA clarify

whether "all equipment from the wellbore to the point of custody

transfer" (as stated in §63.761) includes "ancillary equipment."

Response: Associated equipment is defined in §63.761 to

include all equipment from the wellbore to the point of custody

transfer, except glycol dehydration units and storage vessels

with the potential for flash emissions. Therefore, prior to the

point of custody transfer, ancillary equipment is considered to

be associated equipment and cannot be aggregated to determine

major source status. Therefore, the EPA has not made any changes

to subpart HH in response to this comment.

Comment: Commenter IV-D-07 felt that inserting the

statement about custody transfer does not clarify the meaning of

associated equipment. The commenter explained that custody

transfer usually occurs after a preliminary separation of gas and

liquids, which includes the use of storage vessels with flash

emissions.

In contrast, commenter IV-D-05 stated that the term after

custody transfer is "probably the most universal term that can be

used in regards to clarity." 

Response: As stated in a previous response, the EPA defined

associated equipment to comply with its interpretation of section

112(n)(4)(A) of the CAA. Although storage vessels with the

potential for flash emissions typically occur prior to the point

of custody transfer, the EPA specifically excluded these

emissions sources from the definition of associated equipment in

an effort to focus on significant HAP emission points.

The term "custody transfer" is included in the definition of

associated equipment as the point of delineation for where

emission aggregation of all emission points within a facility may

occur. It is also used as the basic point to define where the

oil and natural gas production source category ends and the

natural gas transmission and storage source category begins. The

exceptions to this are natural gas processing plants, which are
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included in the scope of the oil and natural gas production

source category even though they are considered to be after a 

point of custody transfer. This exception was provided because

natural gas processing plants are typically clearly defined

facilities within this source category. Furthermore, during the

development of the proposed regulations, industry repeatedly

stated that the term custody transfer is well understood within

the industry and that custody transfer of hydrocarbon streams

occurs only once and not multiple times. Therefore, the EPA has

not made any changes to the definition of associated equipment in

response to this comment.
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2.4 HAP EMISSION POINTS

Comment: The EPA specifically requested information and

comments, along with supporting documentation, on HAP emissions

from several emission points. These emission points included:

(1) process vents at amine treating units and sulfur plants,

(2) transfer and storage of pipeline pigging wastes,

(3) combustion sources located at oil and natural gas production

and natural gas storage and transmission facilities, and

(4) storage vessels at natural gas transmission and storage

facilities.

Amine Treaters and Sulfur Units. Commenters IV-D-07,

IV-D-16, IV-D-22, and IV-G-09 responded to the EPA's request for

information on amine treaters and sulfur units. The commenters

stated that amine treaters are most likely small sources of HAP

and there is little available data to estimate HAP emissions from

these sources. Commenter IV-D-07 requested clarification on how

these emissions should be estimated. Commenter IV-D-16

recommended that if amine units and sulfur recovery units are

shown to be significant sources of HAP, they can be controlled

during the residual risk review required by section 112(f) of the

CAA. Commenter IV-D-22 stated that since there are relatively

few units (as compared to glycol dehydration units and storage

tanks), the amine treater unit and sulfur recovery unit totals

would result in an extremely small percentage of total baseline

year HAP for the source category. Commenter IV-G-09 stated that

amine plants are designed to remove carbon dioxide, sulfur, and

other impurities from the gas. According to the commenter, most

aromatic and long chain hydrocarbons are removed from natural gas

for their economic value before the gas treatment in amine

plants. The commenter further explained that the large amount of

non-combustible gases in the vents of amine plants makes flaring

impractical and the high flow rate of these non-condensable gases

makes condensers technically not feasible. At this time, the

commenter stated that they were not able to provide an example of

a practical control technology and recommended not regulating

amine plants under this standard.
2-87

Pipeline Pigging Operations. Commenters IV-D-07, IV-D-08,

IV-D-10, IV-D-16, IV-D-17, IV-D-20, IV-D-22, and IV-G-09

responded to the EPA's request for information on pipeline

pigging operations. According to the commenters, pipeline

pigging activities are performed to remove scale and other

accumulations, and occur intermittently and infrequently with

insignificant fugitive emissions. Commenter IV-G-09 stated that

although there is no set schedule, most transmission lines are

pigged less than once per year, and are open to the atmosphere

for only the few hours required to discharge the liquids and the

solids collected. The commenters stated that pigging wastes are

contained in storage tanks and have minimal emissions. The

commenters requested that the EPA not regulate these sources. 

According to commenters IV-D-07, IV-D-08, IV-D-20, IV-D-22, and

IV-G-09 the wastes generated from pigging are primarily solids

with entrained liquids and contain small amounts of VOC and HAP. 

The commenters concluded that potential HAP emissions from

pipeline pigging operations would be inconsequential in the oil

and natural gas production source category.

Commenter IV-D-10 suggested that, until the EPA has

developed specific requirements and applicability determinations

for HAP emissions from transfer and storage of pipeline pigging

wastes and combustion sources, these units should not be covered

under the oil and gas MACT. The commenter was mostly concerned

with estimating PTE for HAP emissions from transfer and storage

of pipeline pigging wastes and combustion sources from the

gathering portion of their company. Besides the infrequent

occurrence of pigging operations, the commenter stated that there

is no testing method available for measuring these emissions from

the pigging waste storage tanks. According to the commenter,

quantifying emissions from the tanks is difficult. In addition,

the flow is difficult to measure given the unsteady flow

conditions and the variability of the gas composition over time. 

The commenter stated that it would be unfair to the industry to

assume they are major sources due to emissions from pigging since
2-88

there is no ability to test for applicability to the

requirements.

Combustion sources. Commenters IV-D-20 and IV-D-22

discussed combustion sources. The commenters suggested they were

not aware of any existing database that adequately characterizes

the populations of equipment, HAP emissions, or risk of exposure

to the public for combustion sources at oil and gas production

facilities. The commenters also noted that the ICCR had been

initiated, by the EPA, to address combustion sources. Commenter

IV-D-20 also reminded the EPA that combustion sources in the

Appalachian region are unique from those in the Southwest. The

commenter explained that in Appalachia, the oil and gas

production related combustion sources are generally in non-urban

areas, emit small amounts of HAP and pose little if any risk to

human health.

Storage vessels at natural gas transmission and storage

facilities. Several commenters responded to the EPA's request

for information on storage vessels from natural gas transmission

and storage facilities. Commenters IV-D-08, IV-D-12, IV-D-16,

IV-D-35, and IV-G-12 suggested that there are small amounts of 

liquids associated with transmission and storage facilities. The

commenters also stated that the liquids associated with

transmission and storage facilities contain small amounts of HAP,

resulting in insignificant emissions. Commenter IV-D-07 stated

that at some facilities, a small pressure drop exists between a

separator and a storage vessel, so flash emissions are low. 

According to the commenter, many facilities dump separators

straight into a wet header system, and have no flash emissions,

while other facilities may only dump low-pressure separators to

atmospheric storage tanks. The commenter and commenter IV-D-31

recommended that an annual average be used to evaluate "flash

potential" if the EPA decides to regulate storage vessels in the

natural gas transmission and storage category. Commenter IV-D-08

explained that by the time natural gas enters the transmission

facility, most of the liquid has been removed. The commenter

further explained that the entrained liquids are collected in
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barrels and emptied infrequently. According to the commenter,

requiring controls on storage vessels at natural gas transmission

and storage facilities would provide negligible HAP emission

reduction. Commenter IV-D-12 recommended that these sources not

be subject to emission controls unless, and until, the EPA has

collected and analyzed adequate information to demonstrate that

controls are justified. Commenter IV-D-16 suggested that if the

applicability sections of subpart HH and HHH do not overlap, the

tanks that need control will be covered under subpart HH. 

Commenter IV-D-35 stated that very few natural gas transmission

and storage facilities in the State of Colorado use storage

vessels. Commenter IV-G-12 remarked that storage tanks at their

gas storage facilities are used to hold lubricating and fuel oils

for internal combustion engines, or fluids with very low vapor

pressures such as glycol or produced water. According to the

commenter, the calculation of emissions from these tanks for

title V permitting purposes showed that they are of a de minimis

nature.

Response: Based on the comments received, the EPA believes

that process vents at amine treating units and sulfur plants,

transfer and storage of pipeline pigging wastes, combustion

sources located at oil and natural gas production and natural gas

storage and transmission facilities, and storage vessels at

natural gas transmission and storage facilities are not

significant sources of HAP and do not warrant regulation under

subparts HH and HHH. If warranted, combustion sources at natural

gas transmission and storage facilities may be regulated under

future regulations.

However, a recently published report from GRI addressed HAP

emissions from amine treater and sulfur recovery units. The

report indicated that amine treaters and sulfur units are not

significant contributors to overall national HAP emissions from

the oil and natural gas production source category. However, the

report indicated that amine treaters may be significant

contributors to HAP emissions on a site-specific facility basis. 

It should be noted that emissions from amine treaters and sulfur
2-90

recovery units must be taken into consideration by a facility's

owner or operator in making major source determinations. 
2-91

2.5 IMPACTS

2.5.1 Cost Impacts Including Production Recovery Credits

Comment: Commenters IV-D-07 and IV-D-12 stated that the

cost data are not representative of the true impact of subpart

HHH and demonstrates that the data base is inadequate. The

commenters referred to the economic analysis which indicated that

only five facilities would be affected at a collective capital

cost of $57,000. According to the commenters, the size range

examined was 20 to 50 MMscf/d, which is not at all representative

of the dehydration equipment they operate. Commenter IV-D-12

reviewed the proposal and determined that at least four major

sources on their system would be subject to subpart HHH. 

Additionally, the commenter provided an example of condenser

controls equivalent to those proposed in the standard that had

been installed on two dehydration units of 300 MMscf/d each, at a

single site, at a capital cost greater than $500,000. The

commenter remarked that this example demonstrates that the EPA's

understanding of the natural gas transmission and storage source

category is flawed and deficient. The commenter recommended that

the EPA take more time to understand the industry, and to analyze

emissions and cost impacts before proceeding further with the

rulemaking. Commenter IV-D-07 also mentioned that the

recordkeeping costs seem very low.

Commenters IV-D-15 and IV-G-05 stated that based on their

experience, the EPA has underestimated the cost of installation

of condensers and monitoring equipment. As an example, commenter

IV-D-15 stated that a recently purchased natural draft condenser

on a 5.0 MMscf/d glycol dehydrator unit cost more than $14,000,

not including the cost of installation, tanks, and temperature

monitoring equipment. The temperature monitoring equipment (two

temperature sensors and a chart recorder) cost $2,000. The cost

for an installation using an existing tank was closer to $18,000

and did not include costs for additional controls (e.g., a

flare). The commenter, along with commenter IV-G-05, provided

another example of a 20.0 MMscf/d unit where the cost of the

condenser and connections to allow combustion of the vent offgas
2-92

in the glycol reboiler was more than $22,000 for the equipment,

without installation costs or temperature monitoring equipment

costs. The commenters compared their numbers to the costs in the

BID of $11,000 (Table 6.1) for a comparable control scheme

including a new tank for a comparable unit. Commenter IV-G-05

maintained that the costs of condensers and monitoring equipment

may exceed the value of the gas being treated, and some units

will probably shut down to avoid the cost of installing and

maintaining this equipment.

Response: The EPA based its cost estimates on published

installed control system costs from the Ventura County

(California) Air Pollution Control District (APCD). These costs

were associated with a glycol dehydration unit regulation issued

by the Ventura County APCD (Air Docket A-94-04 number IV-A-07). 

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.

However, to address comments received from the natural gas

transmission and storage source category, the EPA collected

additional data from 83 glycol dehydration units located at

natural gas transmission and storage facilities. This additional

information, as well as the information on 31 glycol dehydration

units collected for the proposal, indicated that 71 glycol

dehydration units were controlled. The EPA determined that 59 of

the 71 glycol dehydration units were controlled using a

combustion device, primarily a flare. Based on this new data,

the EPA revised the cost impacts for the natural gas transmission

and storage (Air Docket A-94-04 number IV-A-08). The EPA

estimated that seven facilities would be affected by subpart HHH. 

The EPA assumed that six of the facilities would install flares

to meet the control requirements, and one facility would install

a condenser. Therefore, based on these control scenarios, the

EPA estimated a total capital investment of $280,000 and a total

annual cost of $300,000 per year for the natural gas transmission

and storage source category. This annual cost estimate includes:

(1) the cost of capital, (2) operating and maintenance costs,
11G. Viconovic, EC/R Inc., to M. Smith, EPA:WPCG, and L.

Conner, EPA:ISEG. Cost impact estimates for the oil and natural

gas production and natural gas transmission and storage national

emission standards for hazardous air pollutants. July 9, 1996.

2-93

(3) the cost of monitoring, recordkeeping, and reporting (MRR),

and (4) any associated product recovery credits.

Comment: Commenter IV-D-15 stated that, in their

experience, the cost for implementing a leak detection and repair

(LDAR) program for a natural gas processing plant would cost

approximately $6.50 to $7.50 per component monitored for the

first year and $5.00 to $6.00 per component monitored for

subsequent years. According to the commenter, remote locations

will add to such costs, and these costs do not include repair

work. The commenter calculated first year costs ranging from

$2,600 for the 400 components monitored for the Model "A" Plant

up to $17,250 for the 2,300 components for the Model "C" Plant. 

The commenter compared their costs to the $400 that is provided

in the example in the BID.

Response: The EPA estimated that the total annual costs for

LDAR programs range from $12,000 (in July 1993 dollars) for model

natural gas processing plant "A" to $42,000 for model natural gas

processing plant "C." These costs are documented in a memorandum

contained in the docket (Docket Item II-A-03).11 The $400 (as

shown in Table C-3 of the Background Information Document)

represents additional MRR costs that have not been previously

accounted for in the LDAR program costs.

Comment: Commenter IV-D-10 stated that the EPA did not take

into account the additional costs to companies to dispose of

condensed water as exempt waste. According to the commenter, the

disposal costs in the San Juan Basin of New Mexico are

approximately $1.40 per barrel of water. The commenter stated

that condensing will at least double the water disposal amounts

from dehydrators because steam currently going to the atmosphere

will be condensed. 

Response: Approximately 20 billion barrels per year of

produced water are generated by the oil and natural gas
12The Oil and Gas Exploration and Production Industry. 

Trends: 1985-2000. (Draft Report, April 30, 1993). U.S. EPA,

Washington, DC. (Air Docket A-94-04 number IV-A-09).

13Rueter, C.O., M.C. Murff, and C.M. Beitler (Radian

International LLC). Glycol Dehydration Operations, Environmental

Regulations, and Waste Stream Survey. Prepared for the Gas

Research Institute. Publication Number GRI-96/0049. June 1996. 

Page 4-38.

2-94

production source category.12 Using GLYCalc 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 by approximately 590,000

barrels per year. According to a GRI report,13 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 oil and natural gas production NESHAP would

have a minimal impact on existing produced water disposal costs

and control costs.

Comment: Commenter IV-D-22 stated that the EPA has

substantially understated the cost of subpart HH to industry

sources and has underestimated the monitoring, reporting, and

recordkeeping burdens associated with the rule. The commenter

estimated the capital costs of subpart HH to exceed $25 million

for major sources, as compared to the EPA's estimates of $6.5

million for major sources. The commenter also estimated the

annual costs of subpart HH to be $15 million for major sources,

as compared to the EPA's estimates of $4 million for major

sources. The commenter estimated cost effectiveness to be

$3,000/megagram for the EPA's model plant, as compared to the

EPA's cost effectiveness of $116/megagram for its model plant.

The commenter mentioned the EPA's request for comments on

the production recovery credit assumed to result from

installation of control devices. The commenter believes, based

on GLYCalc runs, that the EPA has materially overstated the
14"National Emissions Standards for Hazardous Air Pollutants

for Source Categories: Oil and Natural Gas Production and Natural

Gas Transmission and Storage - Background Information for

Proposed Standards." EPA-453/R-94-079a. April 1997.

2-95

quantity of product recovered that could be sold to offset the

capital and annual costs associated with subpart HH.

Response: 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. 

In addition, the MRR costs were based on a detailed analysis of

the regulatory requirements of subparts HH and HHH. The EPA

believes that the MRR cost estimates reflect the estimated effort

required to address MRR requirements in the final subparts HH and

HHH.

In reviewing the costs presented by the commenter, the EPA

noted that the commenter compared a 10 MMscf/d unit with a

35 MMscf/d unit, which the EPA used as its example cost model

plant in Chapter 6.0 of the BID. Thus, the commenter observed a

significant difference in product recovered.

Comment: Commenter IV-D-38 made general statements that the

proposed regulations will have a profound impact on their

operations. This includes a cost of implementation that is

enormous compared with environmental benefits and, ultimately,

passing these increased costs to consumers.

Response: The EPA also conducted an economic impacts

analysis to evaluate the impacts of the regulation of affected

producers, consumers, and society (Air Docket A-94-04 numbers

II-A-08 and IV-A-13). The EPA estimated that price and output

changes as a result of the regulation were less than 0.01 of 1

percent, which is significantly less than observed market trends

(based on 1992 and 1993 data). The cost impacts are presented in

tables 1 through 3 of the preamble; the development of these

costs is documented in the background information document.14

Through the comment period, the EPA provided the opportunity for

the public to submit comments, along with supporting
2-96

documentation, on all aspects of the proposed NESHAP. Without

supporting documentation to address the specific impacts of the

proposed NESHAP on the commenter's operations, the EPA is unable

to specifically respond to this comment.

Comment: Commenter IV-G-09 estimated the average cost of

the condenser and auxiliary equipment it placed on dehydration

units, each processing 100 MMscf/d, to be more than $150,000, in

contrast to the EPA's preamble statement that the average cost of

condenser control devices would be less than $12,000.

Response: As previously stated, the EPA based its cost

estimates on published installed control system costs from the

Ventura County APCD (Air Docket A-94-04 number IV-A-07). Without

substantive supporting documentation to address the specific cost

impacts of the NESHAP on the commenter's operations, the EPA is

unable to specifically respond to this comment.

Comment: Commenter IV-D-11 stated that imposing

requirements on sources that are already controlled invalidates

the EPA's cost effectiveness analysis. According to the

commenter, sources controlled under the Louisiana Department of

Environmental Quality (LDEQ) Section 2115 Waste Gas Disposal Rule

already meet the MACT floor efficiency requirements. Therefore,

the commenter stated that the expenditures for monitoring and

recordkeeping requirements will not result in appreciable

emissions reductions. The commenter concluded that the cost

effectiveness for controlled sources could approach infinity

since no additional reductions will be realized. The commenter

referred to the State of Louisiana's implementation of

significant controls on glycol dehydrators and provided a copy of

the pertinent pages of the LDEQ 1995 Annual Report, which shows

that toxic air emissions from glycol dehydrators have been

reduced from 36,720,000 pounds (lb) to 1,277,608 lb in 1994,

representing a reduction greater than 96 percent. According to

the commenter, further reductions have occurred since 1994. The

commenter explained that the great majority of the emissions

reductions are federally enforceable since they were required due

to the Louisiana Administrative Code (LAC) 33:III.2115 Waste Gas
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Disposal Rule and are contained in either State-only or part 70

permit programs in LAC 33:III.Chapter 5. The commenter noted

that these rules are incorporated in the EPA-approved State

implementation plan (SIP) for Louisiana and that further

reductions are being accomplished due to a rule for glycol

dehydrators (LAC 33:III.2116) and for flash gas from storage

tanks (LAC 33:III.2104, Crude Oil and Condensate rule) which are

not included in the EPA-approved SIP.

Response: The commenter seems to imply that the

installation and operation of control equipment are all that is

necessary to achieve the MACT floor efficiency requirement. The

EPA believes that monitoring, recordkeeping, and reporting

requirements serve a vital function in ensuring that an emission

limitation is initially, and continues to be, met. Therefore,

the EPA maintains that the costs associated with monitoring and

recordkeeping are part of the costs that must be incurred to

achieve the necessary emission reduction, not additional costs

with no appreciable emission reduction.

The monitoring, recordkeeping, and reporting requirements

contained in the final rule are the requirements that the EPA

believes are necessary to ensure compliance with the emission

limitations. If the Louisiana rule referred to by the commenter

requires comparable monitoring, recordkeeping, and reporting as

that contained in the final rule, then no additional burden would

be incurred by affected facilities. In fact, via §63.10(a)(3) of

the General Provisions, which is incorporated by reference into

the final rule, an owner or operator can simply send the

Administrator a copy of any report to the State that contains the

same information required by the federal NESHAP. If the

monitoring, recordkeeping, and reporting currently being

conducted by these Louisiana facilities do not meet the

provisions in the final rule, then the EPA believes that these

sources would need to upgrade efforts to ensure compliance with

the MACT standard.

Further, if the State of Louisiana believes that the rule

referenced by the commenter is equivalent to the final standard
2-98

for Oil and Natural Gas Production facilities, then an

application could be made under subpart E of 40 CFR 63. If the

EPA agrees that the Louisiana rule is at least as stringent as

the federal rule, the State rule would replace the federal NESHAP

for source in the State of Louisiana.

2.5.2 Environmental Impacts

Comment: Commenter IV-D-07 stated that the EPA's

assumptions made in estimating emissions are not representative

of their operations, especially HAP concentrations in natural gas

before dehydration. The commenter noted that methane and

volatile organic compounds (VOC) emission reductions are included

in the preamble even though the standard is designed to reduce

HAP emissions. The commenter questioned why methane emissions

were included. 

Response: The EPA used the best available information to

estimate the environmental impacts of subparts HH and HHH. The

information represents average facilities and operating practices

within the source categories and not any individual facility and

facility operations. The EPA included VOC and methane emission

reductions for the proposed regulations for informational

purposes and to show the overall emission reduction benefits

associated with these NESHAP. Methane and VOC reductions were

not used to set the standards for subparts HH and HHH. Therefore

the EPA has not made any changes to subparts HH and HHH in

response to this comment.

Comment: Commenter IV-D-07 stated that the estimates for

increases for nitrogen oxides and sulfur dioxide emissions from

additional flare operations may be severely underestimated.

Response: The EPA used AP-42 emission factors to estimate

the increases in nitrogen oxides and sulfur dioxide emissions

associated with the installation of flares at certain remote

facilities. The EPA believes these estimates are representative

of potential emission increases for this industry. Therefore,

the EPA has not made any changes to these estimates.
2-99

2.6 ECONOMIC ANALYSIS

Comment: Commenter IV-D-19 was concerned that any analysis

of the economic impact of the proposed standard should adequately

consider the impact on marginal production operations. 

Specifically, the commenter mentioned the low crude oil prices

and high level of abandonment of marginal oil production

operations. The commenter indicated that to meet the

requirements of the Regulatory Flexibility Act (RFA), the EPA

screened a sample of small entities and determined that minimal

impacts from subpart HH would result. The commenter requested

assurance or modification of the economic impact analysis to

ensure the screening sample contains an appropriate cross section

of small entities.

Response: The Agency's economic analysis employed a

baseline characterization of the industry that includes marginal

production operations. This baseline characterization linked the

model plants and units developed by the EPA's engineering

analysis with the well groups identified and characterized by the

Gruy Engineering Corporation in their 1991 report prepared for

API. These well groups are defined by production rates in

specified ranges of well depths for both oil and gas wells in

each of the 37 different geographic areas across the United

States. The Energy Information Administration (EIA) report

provides details for oil well groups in Appendix A and for

natural gas well groups in Appendix B. Therefore, to the extent

that the Gruy Engineering Corporation's database appropriately

characterizes marginal production operations, the Agency's

economic analysis includes the impacts on these operations.

The Agency expects that the impacts on these marginal

operations will be minimal given the size cutoff for glycol

dehydration units. Glycol dehydration units that process less

than 3 MMscf/d are not affected by the proposed standards. It is

likely that a large share of the marginal operations operates

these smaller units and, thus, would not incur compliance costs

associated with the proposed standard. Furthermore, it follows

that the smaller owners would likely own only units of this type
2-100

and, thus, would also not be adversely affected by the proposed

standard. However, in accordance with the RFA, the Agency still

conducted an analysis of the small business impacts of the

standards. As noted by the commenter, the Agency employed a

sample of companies to evaluate the small business impacts

because the necessary financial data were not available for each

and every potentially affected company. The sample of 80

companies was determined by data availability and considered a

fair representation based on their distribution across the

relevant SIC codes. To facilitate evaluation of the

appropriateness of the sample, the EIA report provided a list of

the companies that were part of the sample as well as their

baseline data in Appendix F. Based on Small Business

Administration (SBA) size standards, the EPA's sample contained

39 small companies, which were 48.8 percent of all companies. 

Based on this sample, the Agency determined that the mean

cost-to-sales ratio for small companies was 0.1 percent with a

maximum of 1.1 percent. This information supports the Agency's

finding that there will not be a significant impact on a

substantial number of small entities. 

Comment: Commenter IV-D-24 stated that the EPA economic

analysis appears to significantly underestimate the control costs

of the proposed regulation. The commenter estimated that

post-regulatory control costs could be $121.2 million/yr as

compared to the EPA's estimate of $18.9 million/yr. [Note: 

These figures include the costs associated with the regulation of

area sources, which has been deferred until the development of

the Urban Air Toxics Strategy is finalized.]

Furthermore, the commenter estimated that as many as 1,960

wells per year could be abandoned as a result of the increased

compliance costs of the proposed regulation and the EPA estimates

that no wells would be closed prematurely. The commenter

explained that the EPA's determination of abandonment was based

on aggregate changes in corporate revenues and profits. However,

the commenter stated that production decisions are made on a

well-by-well or project basis and if an individual project's
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profits fall below its break-even point, that well will be

abandoned.

The commenter also estimated that an average of 46,000

thousand cubic feet (MCF) of natural gas production could be lost

each year as a direct result of the increased costs of the

proposed exploration and production (E&P) MACT regulation,

compared to the EPA's estimate of 99 thousand cubic feet per year

(MCF/yr). The commenter stated that their sophisticated,

field-specific benefit-cost model and a detailed gas supply

model, to estimate production impacts, provides a more accurate

estimate than the EPA's. 

The commenter noted that the EPA did not estimate losses of

economically producible natural gas reserves. The commenter

estimates that reserve losses could average as much as 1,040

billion cubic feet per year (bcf/yr) through 2010. The commenter

stated that while employment impacts of the proposed rules are

estimated to be minimal in their analysis, the EPA should update

its analysis to include this employment loss.

Response: The Agency's engineering analysis, as summarized

in Section 3 of the EIA report, has estimated the annual

compliance cost of the proposed standard to be almost $19 million

per year, with major sources incurring $7 million annually and

area sources incurring $12 million per year. The Agency's

economic impact results are based on this estimate of the annual

compliance cost of the proposed standard. This estimate differs

significantly from the commenter's estimate of $121.2 million per

year. Therefore, it is not surprising that the commenter's

reported economic impacts are much greater than those reported by

the Agency. The differences in these economic impacts are

attributable to the significant disparity in the cost estimate

used in determining these economic impacts as opposed to the

economic methodology. The Agency expects that input of these

higher compliance costs in its model would likely provide more

comparable impacts to the commenter's "sophisticated" economic

model. In addition, it is not clear whether the commenter has

accounted for the EPA's size cutoff of 3 MMscf/d for TEG
2-102

dehydration units in computing its economic impact results. The

Agency expects that this size cutoff prevents the premature

closure of a large number of small and often marginal well

operations. Not accounting for this size cutoff would similarly

contribute to differences in the estimated reduction in natural

gas production and employment losses associated with the proposed

standards. 

Also, the commenter has misinterpreted the EPA's

determination of closure, or abandonment, as based on aggregate

changes in corporate revenues and profits. Rather, as described

in Section 4 of the EIA 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 the commenter's statement 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." Furthermore, the commenter is

correct in stating that the EPA did not estimate losses of

economically producible natural gas reserves. The economic

analysis conducted by the Agency 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.
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2.7 LEGAL ISSUES [OTHER THAN ISSUES ASSOCIATED WITH THE EPA'S

INTERPRETATION OF SECTION 112(n)(4)(A) AND (B)]

Comment: Commenters IV-D-16, IV-D-22, IV-D-23, and IV-D-34

requested that the EPA clarify that subparts HH and HHH do not

apply to OCS sources. Commenter IV-D-16 specifically recommended

that the definition be modified to clarify that offshore

platforms are not covered. The commenters indicated that

offshore platforms should not be covered by any section 112 rule. 

Commenter IV-D-22 stated that they believe that Congress gave the

EPA limited authority to regulate air emissions from OCS sources. 

According to the commenter, most of the authority for controlling

these emissions was provided to the Department of the Interior

(DOI) and what limited authority was provided to the EPA extends

only to emissions of criteria pollutants. Commenter IV-D-23 also

indicated that the CAA prevents the EPA from regulating HAP in

Federal OCS areas. Commenter IV-D-34 referred to section 328 of

the CAA and stated that it does not provide authority to the EPA

to regulate air toxics under section 112 in any OCS area.

Response: Section 328 of the CAA requires that the

Administrator establish requirements to control air pollution

from OCS sources (i.e., sources located offshore of the States

along the Pacific, Arctic, and Atlantic coasts and along the U.S.

Gulf Coast off the State of Florida eastward of longitude 87

degrees and 30 minutes) to attain and maintain Federal and State

ambient air quality standards and to comply with the provisions

of part C of title I. For sources located within 25 miles of the

seaward boundary of such States, the requirements must be the

same as would be applicable if the source were located in the

corresponding onshore area. Oil and natural gas production

sources emit VOC, which contributes to the formation of ozone,

and is regulated by the national ambient air quality standards

(NAAQS). The primary HAP of concern for these source categories

(benzene, toluene, ethyl benzene, mixed xylenes, and n-hexane)

are also classified as VOC. Therefore, standards for oil and

natural gas production sources are applicable to offshore

platforms, that are OCS sources, because they are related to the
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"attainment and maintenance" of ambient air quality standards or

the requirements of part C of title I of the Act. Furthermore,

section 328 states that the Administrator may exempt an OCS

source from a specific requirement "if the Administrator finds

that compliance with a pollution control technology requirement

is technically infeasible or will cause an unreasonable threat to

health and safety." Since offshore platforms typically control

process vents by routing them to a flare, the EPA has determined

that compliance with the control technology requirements is

technically feasible. Therefore, the EPA has not exempted

offshore platforms that are OCS sources from subpart HH.
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2.8 PERMIT ISSUES

Comment: Commenter IV-D-05 cited a problem with the

aggregation of emissions from associated equipment for major

source determinations. [Note: the commenter mentioned

"ancillary equipment" but most likely meant "associated

equipment" as the comment appears to be directed towards

associated equipment.] The commenter was concerned that 

existing facilities that had made applicability determinations in

the past (e.g., for title V operating permits), based on not

aggregating emissions from glycol units and storage vessels with

the potential for flash emissions, had been permitted and

operated as minor sources. The commenter asked whether these

facilities would be given a "grace period" to pursue title V

operating permits if they were classified as major sources given

the aggregation of the ancillary equipment. The commenter was

concerned that without a grace period, these sites could be

subject to enforcement/penalty, etc.

Response: When making past applicability determinations,

sources may have interpreted the phrase "associated equipment” in

section 112(n)(4) of the Act differently than EPA’s final

interpretation of that phrase. The EPA acknowledges that such

sources may have concluded that they were nonmajor, whereas,

under EPA’s final subpart HH rule, they could be classified as

major. However, the EPA expects the number of sources with this

discrepancy is small. The majority of facilities that are major

under the EPA’s final rule would have applied for title V permits

because they have emission points (e.g., glycol dehydration

units) that are by themselves major. Of the remaining sources,

the EPA expects many to have applied for a title V permit based

on the anticipated interpretation of 112(n)(4) described when the

proposed rule was published. 

For the remaining sources (e.g., those which are major

solely because of aggregation of associated equipment, and which

have not yet submitted a Title V permit application), the EPA

does not agree that a blanket policy granting a "grace period” is

appropriate, and EPA encourages major sources subject to subpart
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HH to apply for a title V permit as expeditiously as possible. 

The EPA will rely on its enforcement discretion in situations

where a source failed to apply for a permit because it determined

that it was nonmajor based on section 112(n)(4) of the Act. In

most cases the EPA does not expect to undertake enforcement

action, so long as the source expeditiously applies for its

title V permit. However, the EPA does not believe it is

appropriate to give up its ability to enforce part 70 in such

instances.

Comment: Commenter IV-D-06 requested that §63.1274(c)

mention that sources exempted by §63.1274(b) are not required by

this subpart to obtain an operating permit. According to the

commenter, sources exempted by §63.1274(b) should not be required

to get an operating permit, since subpart HHH has no requirements

to put into a permit. The commenter stated that this comment may

also apply to subpart HH.

Response: Under proposed §63.1274(b) [now being codified at

§63.1274(d)], only individual units are exempt from the

requirements of proposed §63.1274(a) [now being codified at

§63.1274(c)]. Therefore, major sources would still be required

to obtain a title V permit and include the part 63 requirements

that these sources keep records to document that the design

capacity or benzene emission rate is below the cutoff

(§63.1284(d) for subpart HHH and §63.764 for subpart HH). The

EPA believes that, when a source is required to obtain a title V

permit because it is major, recordkeeping requirements like

§63.1284(d) must be included. Note that in the final rules,

neither subpart HH nor subpart HHH regulates nonmajor sources.

Comment: Commenters IV-D-31 and IV-G-02 requested that the

sections that require major sources of HAP subject to the

proposal to get operating permits [§§63.764(f) and 63.1274(c)],

should be eliminated since the requirements are already well

documented in parts 70 and 71. The commenters explained that

restating these requirements is redundant and can cause confusion

in identifying applicable requirements in an operating permit

application.
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Response: The EPA believes that stating the requirement for

a major source to obtain a part 70 or part 71 operating permit

identifies the facility’s obligation to obtain such permit. The

EPA does not see any reason to remove §§63.764(f) and proposed

63.1274(c) [now codified at §63.1274(e)]. 

Comment: Commenters IV-D-13 and IV-D-37 requested that the

NESHAP not affect the monitoring, recordkeeping, and reporting

requirements for control devices contained in the title V permit,

or other appropriate federal mechanism, at the time the final

NESHAP is promulgated. The commenters remarked that if the

control device is federally enforceable, the monitoring,

recordkeeping, and reporting requirements that have been

acknowledged as federally enforceable and quantifiable by the EPA

are sufficient to ensure HAP emission reductions.

Response: The final rules impose monitoring, recordkeeping

and reporting requirements that are independent from monitoring,

recordkeeping, and reporting for any other applicable

requirement. The EPA cannot assume that any existing control

device requirement, (including monitoring, recordkeeping, or

reporting) is adequate to ensure compliance with the particular

requirements of a new NESHAP. Ensuring compliance with the NESHAP

does not alter existing compliance obligations that are

established for a variety of other reasons. However, the EPA

notes that adding the NESHAP to the title V permit may offer

opportunities to consolidate and streamline these multiple

applicable requirements if they exist. For additional discussion

on how this streamlining can occur, see the March 5, 1996 "White

Paper Number 2 for Improved Implementation of the Part 70

Operating Permits Program."

Comment: Commenter IV-D-14 asked what the role of State and

federal permit limits would be on the major source

determinations.

Response: Major source determinations are in part based on

a source’s PTE. For the purposes of section 112, PTE is defined

in §63.2 such that any physical or operational limitation on the

capacity of a source to emit a pollutant, including air pollution
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control equipment and restrictions on hours of operation, shall

be treated as part of the unit’s design if the restriction is

federally enforceable. For additional information on limiting

PTE for section 112 purposes and for other reasons, please see

the following memoranda: (1) January 25, 1995 Memorandum from

John Seitz, Director, OAQPS, entitled "Options for Limiting the

Potential to Emit (PTE) of a Stationary Source Under Section 112

and Title V of the Clean Air Act;" (2) August 27, 1996 Memorandum

from John Seitz, Director, OAQPS, entitled "Extension of January

25, 1995 Potential to Emit Transition Policy;" and (3) July 10,

1998 Memorandum from John Seitz, Director, OAQPS, entitled

"Second Extension of January 25, 1995 Potential to Emit

Transition Policy and Clarification of Interim Policy."
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2.9 ENFORCEMENT ISSUES

Comment: Commenters IV-D-06, IV-D-07, and IV-D-14 stated

that parameter monitoring data do not, by themselves, demonstrate

compliance or noncompliance with emission standards. According to

these commenters, along with commenter IV-G-09, inability to

demonstrate compliance does not prove noncompliance. Commenter

IV-D-14 stated that the assumption that an emission limit has

been exceeded is not valid and the burden of proof for violation

of emission standards should lie on the agency enforcing the

rule.

Commenter IV-D-06 referred to the history of the HON and the

compromise between industry and the EPA on classifying monitoring

excursions as violations. According to the commenter, excursions

should not be classified as violations of the emission limit. 

Instead, they should be classified as violations of an operating

requirement (the requirement to keep daily averages within the

approved limit). This commenter, along with commenters IV-D-12

and IV-G-09, suggested that is incorrect to define an excursion

as a violation of the emission standards. Commenter IV-D-14

asked what the basis was for establishing that a violation of an

operating parameter value automatically constitutes a violation

of an applicable emission standard.

According to commenter IV-D-06, subpart HHH should be

revised to require that industry "operate with the daily averages

within the approved limit, except as otherwise provided in this

subpart." The commenter further stated that subpart HHH should

then require that "excursions violate that paragraph." The

commenter requested that the EPA delete all portions of subpart

HHH that currently say excursions violate the emission standard. 

According to the commenter, the EPA can assess the same

penalties. The commenter provided the following specific

portions of subpart HHH to be amended (Note: the commenter stated

that corresponding portions of subpart HH should also be amended,

if applicable).

C Section 63.1271 (definition of "operating parameter value"): 

instead of "determines that an owner or operator has
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complied with an applicable emission limitation or

standard," say "indicates proper operation of the control

device."

C Section 63.1274(d): Delete. C Section 63.1281(d)(4)(iii): Revise to say that, except as

otherwise provided in this subpart, any excursion is a

violation of the provisions of section 63.1281(d)(4)(ii).

In addition, commenters IV-D-07 and IV-D-12 recommended that

excursions outside the defined operating window should be a

notice for corrective or preventive action, instead of a

violation of the standard. According to commenter IV-D-12,

short-term excursions from the operating window do not result in

exceedence of "properly structured emissions limitations."

Commenter IV-D-07 claimed that the proposal is inconsistent with

other regulatory initiatives, such as the Compliance Assurance

Monitoring (CAM) rule. 

In contrast, commenter IV-D-35 supported provisions, like

those contained in §63.764(h)(2), that plainly state that

noncompliance with operating parameters is a violation of the

emission limitation or standard.

Response: The EPA's decision to classify a violation of an

operating parameter as a violation of the emission standard

versus a violation of the operating requirement is based on

whether the monitored parameters have a strong correlation to

control device operation. In other words, do the monitored

parameters accurately predict control device performance? For

combustion units to achieve complete combustion, sufficient

reactor space, residence time, turbulence, and temperature are

necessary. A high combustion temperature must be provided to

ignite the vent stream HAP constituents. Therefore, since

reactor space, residence time, and turbulence are design

parameters, temperature can be used as an accurate prediction of

combustion device operation.

For condensers, GRI has published a report entitled "Control

Device Monitoring of Glycol Dehydrators: Condenser Efficiency
15Reuter, C.O., et al (Radian International LLC). Control

Device Monitoring of Glycol Dehydrators: Condenser Efficiency

Measurements and Modeling, Volume 1. Prepared for the Gas

Research Institute. Publication Number GRI-97/0005.1 January

1997. 134 pp.

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Measurements and Modeling,"15 in which condenser outlet

temperature was evaluated as a sufficient monitoring parameter

for glycol dehydrator vent condensers. In the report, GRI

concluded that outlet temperature is a sufficient monitoring

parameter for indicating control device performance.

Because of these correlations for combustion devices and

condensers, the EPA believes that monitoring temperature is

strong indication of control device performance. The EPA

maintains that a violation of an operating parameter value should

be classified as a violation of the emission standard. 

Therefore, the EPA has not made any changes to subparts HH and

HHH in response to this comment.

Comment: Commenter IV-D-06 stated that subpart HHH does not

appear to define what constitutes an excursion, although it

provides that excursions are violations. The commenter suggested

that excursions should be defined by the daily average parameter

value, not each monitored data point. The commenter recommended

that the EPA modify §63.1281(d)(4)(ii) to clarify that industry

is required to keep the daily average parameter value within the

limit. The commenter also recommended that the EPA include the

definition of an excursion shortly after this paragraph. The

commenter stated that this comment also applies to subpart HH. 

Commenter IV-D-06 was also concerned that each individual

data point might be considered a violation of subpart HHH. The

commenter stated that a single missing data point is not an

excursion. Instead, a "data quality" excursion should mean that

less than 75 percent of the required data were collected. During

development of the HON, the industry stated that two types of

excursions exist: "parameter" and "data quality." The industry

contended that no matter how carefully the monitoring systems are

operated, sometimes a data point would not be recorded. The
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industry stated that if 100 percent of the data were required to

be collected, compliance would be impossible. Commenter IV-D-35

was also concerned that the proposed regulations do not contain

many quality assurance/quality control provisions or a minimum

availability of time for the monitoring equipment. The commenter

suggested including a provision requiring 95 percent data

availability of continuous monitoring systems on an annual

(8,760 hours) basis. The commenters stated that this comment

also applies to subpart HH.

Response: The EPA agrees with the concepts suggested by the

commenters and has made several changes to subparts HH and HHH in

response with these comments. Section 63.773(d)(4) of final

subpart HH and §63.1283(d)(4) of final subpart HHH require the

owner or operator to calculate the daily average for each

monitored parameter and require that the daily average consist of

valid data points for at least 75 percent of the operating hours

in an operating day. For condensers, the owner or operator has

the option of converting the daily average temperature to an

annual average (subpart HH) or a 30-day average (subpart HHH)

condenser removal efficiency. In addition, the following

requirements have been added to §§63.773(d) and 63.1283(d):

1. An excursion for a given control device has occurred when

monitoring data or lack of monitoring data result in one of

the following: C The daily average value of a monitored parameter is less

than the minimum operating parameter limit (or greater than

the maximum operating parameter limit, if applicable)

established for that operating parameter. C If applicable, the 365-day average condenser efficiency is

less than 95 percent, unless the owner or operator has less

than 365 days of data, the average condenser efficiency is

less than 90 percent.

C Monitoring data are not available for at least 75 percent of

the operating hours.

C The vent stream has been diverted through the bypass device.

2. Each excursion is a violation of the operating parameter

limit and thus a violation of the standard (either subpart

HH or HHH).

3. For each control device (or combination of control devices

installed on the same HAP emissions unit), one excused

excursion is allowed for each semi-annual period

(corresponding to the periodic reporting periods specified

in §§63.775 and 63.1285).
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4. Excursions are not considered violations and do not count as

excused excursions during the startup, shutdown and

malfunction events (provided the facility operates according

to the startup, shutdown, or malfunction plan), and during

periods of nonoperation of the unit or process that is

vented to the control device.

Comment: Commenter IV-D-06 noted that subpart HHH allows

for owner or operator to choose the parameter limits and in some

cases may not be restricted to performance tests. The commenter

recommended that the EPA use a concept from the HON where the

owner or operator establishes the approved parameter limit, which

does not necessarily have to be based on a performance test. In

cases where the owner or operator is not otherwise required to

conduct a performance test, the parameter limit may be based on

engineering assessments or manufacturers' data if desired. The

commenter suggested that the EPA clarify subpart HHH by borrowing

from other MACT standards that explain in greater detail when to

use performance test data, and when using other data is

permissible, in establishing parameter limits. The commenter

suggested that the EPA use the Group I and Group IV Polymers

rules as a model. The commenter stated that this comment also

applies to subpart HH.

Response: The EPA does not intend to restrict when an owner

or operator should use performance test data or design analyses. 

The owner or operator may decide whether a performance test or a

design analysis will provide accurate data for determining an

appropriate minimum or maximum operating parameter value. 

Proposed §§63.771(d)(3)(iii)(B) and 63.1281(d)(3)(iii)(B) [now

codified at §§63.772(e)(4)(ii) and 63.1282(d)(4)(ii)] state that

if the owner or operator and the Administrator do not agree on

the demonstration of control device performance using a design

analysis, then the disagreement shall be resolved using the

results of a performance test.

Sections 63.773(d)(5) and 63.1283(d)(5) of the final rules

contain the requirements for establishing minimum (or maximum)

operating parameter limits. These requirements specify that the

owner or operator must establish the appropriate operating
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parameter limit using performance test data, or a design

analysis. Both performance test data and the design analysis may

be supplemented using control device manufacturer's information.

Comment: Commenter IV-D-06 noted that subpart HHH does not

allow for any excused excursions. The commenter recommended that

each monitored control device or recovery device be given a

specified number of excused excursions where the number of

excused excursions starts larger and becomes smaller with time. 

The commenter referred to the development of the HON, where the

industry raised the concern that no matter how carefully a

control device is operated and maintained, sometimes there will

be an excursion. The industry maintained that these excursions

are most frequent when a control device is new and is being

debugged, but they will decrease over time. Therefore, the

commenter recommended that the EPA modify §63.1281(d)(4)(ii) by

using §63.152(c)(2)(ii)(B) of the HON, which says:

(B) The number of excused excursions for each

control device or recovery device for each semiannual

period is specified in paragraphs (c)(2)(ii)(B)(1)

through (c)(2)(ii)(B)(6) of this section. This

paragraph applies to sources required to submit

Periodic Reports semiannually or quarterly. The first

semiannual period is the 6-month period starting the

date the Notification of Compliance Status is due.

(1) For the first semiannual period - six excused

excursions.

(2) For the second semiannual period - five

excused excursions.

(3) For the third semiannual period - four

excused excursions.

(4) For the fourth semiannual period - three

excused excursions.

(5) For the fifth semiannual period - two excused

excursions.

(6) For the sixth and all subsequent semiannual

periods - one excused excursion.

The commenter stated that this comment also applies to

subpart HH.

Response: The compliance dates for subparts HH and HHH

allow owners and operators three years after the effective date

of the rule to achieve compliance. The EPA believes that there

is sufficient time for an owner or operator to debug control
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devices and monitors. Furthermore, by allowing for a small

amount of missing data, and by specifying that a violation of the

operating parameter is defined by the daily average parameter

value, the EPA believes that owners and operators have sufficient

flexibility to operate and maintain their control devices. 

Therefore, the EPA maintains that only one "excused excursion"

should be allowed per semiannual period [codified at

§§63.773(d)(8) and 63.1283(d)(8)].

Sections 63.773(d)(8) and 63.1283(d)(8) also state that

during startup, shutdown and malfunction events, as long as the

owner or operator complies with the facility's startup, shutdown

and malfunction plan, any monitored parameters outside its

operating range would not be counted towards the excused

excursions. However, simply following a startup, shutdown, and

malfunction plan is not necessarily a defense to failure to have

taken steps to prevent malfunctions or failure to adequately

minimize emissions during startup, shutdown, and malfunction

events (§§63.762 and 63.1272). Also, during periods of

nonoperation of the unit or process that is vented to the control

device, monitored parameters outside their established operating

ranges do not count as excursions.

Comment: Commenter IV-D-06 stated that monitoring data

collected during startups, shutdowns, and malfunctions, or

periods of non-operation, should be excluded from daily averages. 

The commenter noted that since daily averages are not mentioned,

this concept is also not mentioned in the subpart HHH. The

commenter stated that in the General Provisions, normal emissions

standards do not apply during startups, shutdowns, and

malfunctions. During those periods, compliance is determined

based on the facility following the provisions in the startup,

shutdown, and malfunction plan. The commenter recommended that

the EPA borrow the following concepts from §§63.152(c)(2)(ii)(C)

and 63.152(f)(7) of subpart G and incorporate them into

§63.1281(d)(4)(ii) (note that wording would have to be changed):

(C) If a monitored parameter is outside its

established range or monitoring data are not collected
2-116

during periods of startup, shutdown, or malfunction

(and the source is operated during such periods in

accordance with the source's startup, shutdown, or

malfunction plan as required by §63.6(e)(3) of subpart

A of this part) or during period of non-operation of

the chemical manufacturing process unit or portion

thereof (resulting in cessation of the emissions to

which the monitoring applies), then the excursion is

not a violation and, in cases where continuous

monitoring is required, the excursion does not count

toward the number of excused excursions for determining

compliance.

! ! !

(7) Monitoring data recorded during periods

identified in paragraphs (f)(7)(i) through (f)(7)(v) of

this section shall not be included in any average

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;

(iii) Shutdowns;

(iv) Malfunctions; and

(v) Periods of non-operation of the chemical

manufacturing process unit (or portion thereof),

resulting in cessation of the emissions to which the

monitoring applies.

The commenter stated that this comment also applies to

subpart HH.

Response: As stated in a previous comment, the EPA has

included provisions for one excused excursion and has

incorporated the suggested concepts from §63.152(e)(2)(ii)(C)

[codified at §63.773(d)(8) and 63.1283(d)(8) of the final rules]. 

The EPA also agrees that monitoring data collected during

startups, shutdowns, and malfunctions, or periods of

non-operation, should be excluded from the daily averages. 

Therefore, the EPA has incorporated the suggested concepts from

63.152(f)(7) of subpart G and incorporated them into

§§63.774(b)(3) and 63.1284(b)(3) of the final rules.

Comment: Commenter IV-D-06 expressed concern that each

monitored parameter would be considered a separate violation of

subpart HHH. According to the commenter, if a control device has
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two or more parameters that must be monitored, and more than one

parameter has a daily average outside the approved limit on the

same day, this should be considered a single excursion. During

the development of the HON, the industry explained that operating

parameters are generally interrelated, so no matter how many

parameters are outside the limit, there is only one opportunity

for emissions to be above the standard. The industry felt that

it would be unfair to multiply the violations by considering each

parameter separately. 

Response: The EPA agrees with the commenter. Sections

63.773(d)(6) and 63.1283(d)(6) of the final rules state that for

a control device or recovery device where multiple parameters are

monitored, if one or more of the parameters meets the criteria

for an excursion, this is considered a single excursion for the

control device.

Comment: Commenter IV-D-14 asked how the EPA would

initially administer the new program. The commenter also asked

what the States' role would be in administering the program and

how delegation would be afforded to the States.

Response: Section 112(l) of the Clean Air Act grants the

Administrator the authority to approve State programs to

implement and enforce section 112 rules. Subpart E of part 63

establishes the procedures for States to follow in obtaining

delegated authority as provided in section 112(l). This subpart

establishes the procedures for:

C the approval of State rules or programs to be implemented

and enforced in place of section 112 Federal rules, emission

standards, or requirements; C the approval of State programs to implement and enforce

section 112 Federal rules as promulgated without changes;

and

C the approval of State rules or programs that adjust a

section 112 Federal rule.

Any request for approval under subpart E must meet all

section 112(l) approval criteria specified by the applicable

Federal rule, and the approval criteria in §63.91(b) of

subpart E. The EPA expects that by the compliance dates of

subparts HH and HHH, the States programs to implement and enforce
16Memorandum from Jones, L.G., U.S. EPA/Emissions

Measurement Branch, to J.D. Mobley, U.S. EPA/ Emission Factor and

Inventory Group. "Glycol Dehydrator Emissions Test Report and

Emissions Estimation Methodology." April 13, 1995.

2-118

these subparts will have been approved by the Administrator under

subpart E. Delegation of authority will be specified in §§63.776

and 63.1286. However, in the case that delegation is not made,

then the EPA Regional Administrator for that State would

implement the standard. 

Comment: Commenters IV-D-07, IV-G-09, and IV-D-31 were

concerned with the limitations of GLYCalc and noted that the

GLYCalc instruction manual states that it over predicts

emissions, usually by at least 20 percent. The commenters

recommended GLYCalc not be used for enforcement purposes unless a

disclaimer on its use for enforcement purposes is included.

Response: The EPA performed field tests to assess the

effectiveness of the GLYCalc emissions model for estimating HAP

and VOC emissions.16 Based on the results of the field test

evaluations, and additional glycol dehydrator emissions test

sponsored by GRI and API, the EPA has recommended that the

GLYCalc model be included in guidance for State and local agency

use for the development of emissions inventories to meet CAA

requirements. The EPA stated that for sites where source tests

have been conducted, the experience was that GLYCalc either

estimates emissions accurately or overestimates emissions. 

According to the EPA’s analysis, the likelihood of overestimating

emissions may be reduced by obtaining accurate measurements of

process variables for as many model inputs as possible. However,

since the use of default values for model inputs will

occasionally be necessary, some overestimation of emissions is

unavoidable.

Therefore, based on the EPA’s analysis, the EPA believes

that GLYCalc is a reasonable method for estimating benzene

emissions from glycol dehydration units for the 1-tpy exemption

and for use in conjunction with the Atmospheric Rich/Lean (ARL)
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method as an alternative to the performance procedures for

condensers.

It should be noted that the EPA does not require the use of

GLYCalc, but has offered it as an acceptable tool for estimating

emissions and demonstrating compliance. However, owners and

operators should be aware that it is possible that a performance

test could indicate that a glycol dehydration unit is out of

compliance. Therefore, the EPA recommends that if GLYCalc

predicts that the glycol dehydration unit is operating close to

the emission limitations in the NESHAP, then the owner or

operator may wish to conduct a performance test.
17Reference 9, appendix B.

18Reference 9. Appendix B.

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2.10 CONTROLS

2.10.1 MACT Floor

Comment: Commenter IV-D-07 noted that the EPA assumed an

average inlet BTEX concentration of 200 ppmv as the basis for the

95 percent HAP reduction. According to the commenter, if the

BTEX concentration is well below 200 ppmv, the required reduction

would be much more difficult to obtain for condensers. The

commenter stated that they felt the EPA did not consider this

scenario or allow for a cost-effective solution. The commenter

noted that for a combustion device, the 95 percent reduction

should not be a problem.

Response: The commenter's statement that the 95 percent HAP

reduction requirement was based on an average inlet BTEX

concentration of 200 ppmv is incorrect. Instead, the 95 percent

control requirement was developed as the floor level of control

(see Air Docket A-94-04, number II-A-07 for further discussion on

the MACT floor development).

The national average BTEX concentration was developed to

estimate national emissions. The EPA developed three national

average BTEX concentrations for natural gas to represent three

sectors in the oil and natural gas production and natural gas

transmission and storage source categories: (1) 200 ppmv for

production; (2) 160 ppmv for processing; and (3) 13 ppmv for

transmission and storage.17 To develop the national emission

impacts, the EPA distributed concentrations of BTEX among the TEG

unit populations.18 Therefore, since the 95-percent emission

reduction was not based on the average BTEX concentrations, the

EPA did not see any reason to modify subpart HH in response to

this comment.

However, the final rule requires an owner or operator to

control process vents on glycol dehydration units to one of the

following: (1) 95 percent HAP emission reduction, (2) 20 ppmv
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control device outlet concentration (for combustion devices), or

(3) control device outlet mass emission rate less than 1 tpy of

benzene. The benzene limitation was established because the MACT

floor for glycol dehydration units with actual benzene emissions

less than 1 tpy was determined to be no control (see responses in

section 2.10.3 of this document). The EPA believes that the

addition of the 1 tpy benzene emission limitation provides

additional flexibility for owners or operators of facilities with

low BTEX concentrations in the natural gas.

Comment: Commenter IV-D-06 requested that the EPA allow an

emission limit of 20 ppmv for non-combustion control devices. 

The commenter stated that at very low incoming HAP

concentrations, recovery devices may be unable to achieve

95 percent HAP reduction, but can probably achieve 20 ppmv HAP at

the outlet reliably. The commenter was concerned that they would

be forced to use combustion devices rather than recovery devices. 

The commenter remarked that the combustion device would be

allowed to emit the same 20 ppmv that the recovery device was not

allowed to emit and that recovery for reuse is environmentally

better than destruction. The commenter recommended that the EPA

add a 20 ppmv option to §63.1281(d)(1)(ii), using

§63.1281(d)(1)(i)(B) as a pattern, without the correction to

3 percent oxygen. The commenter stated that this comment also

applies to subpart HH.

Response: In the preamble to the proposed 40 CFR part 60,

subpart NNN, NSPS for Air Oxidation Unit Process (48 FR 48932,

October 21, 1983), the EPA stated that 20 ppmv is the lowest

outlet concentration of total organic compounds achievable by the

combustion of low organic concentrations (i.e., inlet

concentrations of 2000 ppmv or less). As stated in the preamble

to subpart NNN, the outlet concentration was established based on

kinetic calculations of incinerators. It was demonstrated that,

at a given temperature and residence time, a stream with a low

inlet concentration (approximately 2000 ppmv) could not be

controlled in an incinerator to an outlet concentration below

20 ppmv. The commenter did not provide any information
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indicating that non-combustion control devices could not meet an

outlet concentration below 20 ppmv. Therefore, the EPA does not

see any reason to modify subparts HH and HHH in response to this

comment.

Comment: Commenter IV-D-21 was concerned that documenting

95 percent reduction might be difficult for some dehydrator

configurations that have a flash tank. According to the

commenter, less than 2 percent of the total uncontrolled HAP

emissions from a dehydrator are associated with the flash gas. 

The commenter explained that for dehydrators that route vent gas

to a condenser to recover hydrocarbons, and route flash gas to a

combustion device, the compliance determination would depend on

defining the emission reduction achieved by both control devices. 

Based on the small amount of HAP emissions associated with the

flash gas, the commenter suggested that testing the combustion

device in accordance with proposed §63.772(e) to document control

efficiency would significantly increase compliance cost with

little environmental benefit.

The commenter also noted that flash gas has a high British

thermal unit (Btu) content and is easily burned. The commenter

requested that the EPA provide a default reduction efficiency in

the final rule that can be used by combustion systems burning

flash gas for use in demonstrating compliance with the

requirement for a 95-percent reduction efficiency.

Response: The EPA believes that subparts HH and HHH provide

sufficient flexibility in demonstrating compliance for owners and

operators that route the glycol dehydration unit reboiler vent

gases to a condenser for hydrocarbon recovery and route the flash

gas vent to a combustion device. First, final subparts HH and

HHH allow combinations of control devices to achieve the

95 percent emission reduction [final §§63.765(b)(1)(i) and (ii)

and 63.1275(b)(1)(i) and (ii)]. Second, the final rules do not

require control of HAP emissions from flash tanks if the total

HAP emissions to the atmosphere from the glycol dehydration unit

process vent (i.e., the combined reboiler and flash tank vents)

are reduced by 95 percent [§§63.765(c)(3) and 63.1275(c)(3)]. 
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Finally, subparts HH and HHH provide owners and operators the

option of demonstrating compliance using either a performance

test or a design analysis [§§63.772(e) and 63.1282(d)]. The EPA

believes that by providing the option of performing a design

analysis rather than a performance test, owners and operators

have the flexibility to choose the least expensive option.

As for the commenter's request for a default reduction

efficiency for combustion devices burning flash gas, the EPA

points to §63.771(d)(1)(i) in final subpart HH and

§63.1281(d)(1)(i) in final subpart HHH which state that an owner

or operator may install enclosed combustion devices that meet one

of the following conditions: (1) reduces HAP emissions by

95 percent or more, (2) reduces the outlet HAP concentration to

20 ppmv or less, (3) operates at a minimum residence time of 0.5

seconds at a minimum temperature of 760oC, or (4) is boiler or

process heater that is designed so the vent stream is introduced

into the flame zone. If the owner or operator can demonstrate

that their combustion device operates according to the minimum

residence time and temperature specifications or the vent stream

is introduced into the flame zone, then a compliance

demonstration with the 95-percent emission reduction (or the

20 ppmv outlet concentration) is not required. Therefore, the

EPA believes that it is not necessary to provide a default

reduction efficiency for demonstrating compliance with the

95-percent reduction efficiency.

Comment: Several commenters objected to the 95-percent

control requirement. According to commenter IV-D-12, a

90 percent control requirement would provide a more realistically

achievable standard. The commenter pointed to a GRI study

(Skinner and Rueter, 1998, GRI-98/0073) which shows that

condensers at many facilities are unable to achieve 95 percent on

a continuous basis. The commenter further stated that applying

the control requirement based on the source's choice of either

total VOC or HAP is appropriate, but not both.

Commenter IV-D-16 stated that condenser performance is

dependent on local climate conditions, and that a 95-percent
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efficiency cannot be reliably achieved throughout the year in

many areas of the United States. The commenter was concerned

that requiring efficiencies that could not be met would remove

condensers from the potential control list. The commenter

further remarked that condensers are a form of recycling and

should not be "saddled with an efficiency requirement they cannot

meet." The commenter suggested that an efficiency of 85 percent

more accurately describes the performance in these devices and

should be chosen as the required level of control for subparts HH

and HHH. Commenter IV-D-38 also recommended that an emission

reduction of 85 percent would be typically achieved for the

control devices addressed in section 63.765(c)(2) and (3), as

compared with 95 percent in the proposed regulations, and that

the cited paragraphs should be changed accordingly.

Commenter IV-G-07 presented HAP efficiency data for twenty

condenser-controlled glycol units, each treating between 5 and

55 MMscf/d, and only one of which has no flash tank. According

to the commenter, the calculated mean annual control efficiency

based on this data is 95.97 percent and the standard deviation

error is 2.81 percent. Therefore, the commenter recommended 90

percent as the appropriate lower limit, using this data as

representative and taking the common scientific approach of using

plus or minus two standard deviations as the proper confidence

limit.

Commenter IV-G-02 was concerned about the EPA's setting a

MACT floor for dehydration units based on a "control level

estimated to be achieved through the use of condensers" (63 FR

6304), rather than on the "emission limitation achieved" as

required by the Act. The commenter questioned whether the EPA

has considered that many condensers located at an altitude

probably cannot meet 95 percent (due to lower atmospheric

pressure, substances exhibit a greater partial pressure, and are

therefore more difficult to condense). The commenter also

questioned whether the EPA has data to show the average of the

best performing 12 percent of units achieve a 95 percent

reduction. The commenter stated that they believe that the MACT
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floor is an equipment standard (rather than efficiency, which is

appropriate) requiring a condenser, combustion device, or flare

for control.

Response: The MACT standard for process vents on new and

existing glycol dehydration units was set at the floor level of

control. As required under section 112(d) of the Act, the EPA

developed the MACT floor based on ". . . the average emission

limitation achieved by the best performing 12 percent of the

existing sources. . . ." A detailed discussion regarding the

development of the MACT floor can be found in the docket (Air

Docket A-94-04, number II-A-07). Through section 114

questionnaires, site visits, meetings with stakeholders, and

available literature, the EPA obtained information for 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 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 glycol dehydration units in the oil and natural gas

production source category. Since the 95-percent emission

reduction allows owners and operators to install not only

condensers, but also combustion devices, as long as they achieve

a 95-percent HAP emission reduction, the EPA does not believe

that the MACT floor is an equipment standard.

Although the EPA did not lower the required emission

reduction in the final rule, the final rule requires compliance

with the 95-percent HAP emission reduction to be demonstrated on

a daily basis with an option for compliance using condensers to
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be demonstrated using a 365-day rolling average for the oil and

natural gas production source category, and a 30-day rolling

average for the natural gas transmission and storage source

category (see section 2.10.2 of this document for further

discussion on averaging periods).

Regarding the commenter's concern about condensers located

at a high altitude, although differences in altitude do affect

condenser performance, the EPA expects the effect to be minimal.

Comment: Commenter IV-D-01 requested that the EPA

reevaluate the MACT floor for new sources and require new sources

to control HAP emissions by 98%. According to the commenter,

Louisiana has many facilities that achieve a 98% or greater

control device efficiency by means of a condenser and closed vent

system routing non-condensables to the glycol reboiler firebox.

Response: Based on the available information (i.e.,

primarily section 114 questionnaire responses), the EPA did not

identify a method of control applicable to all types of new

sources that would achieve a greater level of HAP emission

reduction than the MACT floor for existing sources. Furthermore,

the EPA believes that requiring 98 percent emission reduction for

sources in the oil and natural gas production and natural gas

transmission and storage source categories would involve the

destruction of nonrenewable resources and does not encourage

pollution prevention.

Comment: Commenter IV-D-25 emphasized that catalytic

incineration is an effective control option. According to the

commenter, minimum temperature and residence time requirements

are lower for catalytic oxidation as compared with thermal

oxidation, resulting in less expense required for fabrication. 

The commenter requested that §63.771(d)(1)(i) be modified to

include: "(D) For catalytic incineration, operates at a minimum

residence time of 0.03 to 0.05 second at a minimum temperature of

340oC." The commenter stated that these requirements would be

adequate for more than 95 percent destruction of the HAP. 

Response: The EPA believes that the 0.5 second residence

time and 760oC minimum temperature requirements for enclosed
19 U.S. Environmental Protection Agency. Hazardous Air

Pollutant Emissions from Process Units in the Synthetic Organic

Chemical Manufacturing Industry - Background Information for

Proposed Standards. Volume 1B: Control Technologies. EPA

Number EPA-453/D-92-016b., November 1992.

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combustion devices are sufficient to ensure compliance with the

95-percent HAP emission reduction requirement.19 The commenter

did not provide any data to justify that a 0.03 to 0.05 second

minimum residence time and 340oC minimum temperature would be

adequate to achieve a 95-percent HAP emission reduction for all

catalytic incinerators. Furthermore, the EPA does not have the

available data to determine whether catalytic incinerators with

these minimum specifications would meet the 95-percent emission

reduction requirements. Therefore, the EPA has not modified

subparts HH and HHH in response to this comment. 

However, owners or operators may use a catalytic incinerator

with the parameters specified by the commenter, provided the

performance test or design analysis [prepared as specified in

§§63.772(e) and 63.1282(d)] shows that the control device meets

the required HAP emission reduction efficiency.

2.10.2 Averaging Period

Comment: Commenters IV-D-08 and IV-D-20 noted that

§§63.771(d)(1)(i)(A) and 63.771(d)(1)(ii) do not state averaging

periods for the 95 percent control efficiency determination. 

Several commenters were concerned with demonstrating compliance

with the 95 percent control efficiency on a continuous basis. 

Commenter IV-D-12 stated that the proposal for a 15-minute

averaging period is inappropriate and could not be consistently

achieved due to swings in ambient conditions over which the

source has no control. Commenters IV-D-04, IV-D-08, IV-D-12,

IV-D-15, IV-G-05, and IV-G-09 requested that the EPA require

calculation of control efficiency on a monthly or 30-day basis

and commenters IV-D-20, IV-D-22, IV-D-23, IV-D-30, IV-D-34,

IV-G-02, requested a 12-month rolling or annual basis for all TEG

units subject to a 95 percent control requirement. Commenter

IV-D-31 supported either a 30-day or a 12-month averaging period. 
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Commenter IV-G-02 stated that a 12-month rolling average is more

appropriate, considering the types of risks involved, still

provides the EPA with enforceable numbers, and more appropriately

reflects the frequency of the reporting periods required in the

proposal. Commenter IV-G-03 stated that continuous compliance

could be achieved in the winter months and recommended that

continuous compliance determination be based on an annual

average, using rolling monthly data. All of 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. Commenter IV-D-04 explained that flow conditions in

dehydrators fluctuate over time and a 15-minute compliance period

would cause many units to be out of compliance that would be in

compliance over a longer period. The commenter suggested that

the shorter averaging time would make the control requirement

more rigorous than the EPA may have intended. Moreover,

commenters IV-D-20 and IV-D-22 stated that they believe longer

averaging periods are consistent with the MACT floor.

Commenters IV-D-10, IV-D-20, IV-D-22, IV-D-30, IV-D-34, and

IV-G-11 stated that the data collected under section 114 do not

support a MACT floor determination of 95 percent on a continuous

basis. According to the commenters, the section 114

questionnaire did not ask for the averaging period. Furthermore,

commenters IV-D-20, IV-D-22, and IV-G-11 stated that respondents

to the EPA's section 114 survey most likely did not provide

estimated efficiency on a continuous basis because the data to

make that evaluation were not available. According to the

commenters, to provide an estimate of condenser efficiency, most

respondents would have relied on vendor data or short duration

tests and would not have considered seasonal or diurnal

variations.

In support of a monthly or annual averaging period,

commenters IV-D-07, IV-D-08, IV-D-10, IV-D-15, IV-D-20, IV-D-22,

IV-D-23, IV-D-27, and IV-D-31 stated that condensers and flash
20GRI, "Investigation of Condenser Efficiency for HAP

Control from Glycol Dehydrator Reboiler Vent Streams: Analysis

of Data from the EPA 114 Questionnaire and GRI's Condenser

Monitoring Program," Table 3-1 (March 1998).

21Reference 20.

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tanks cannot achieve 95-percent HAP reduction continuously during

the hotter months. The commenters referenced a report by GRI,20

which illustrated that high ambient temperatures cause the

control efficiency to drop below 95 percent. However, the report

showed that condensers could meet 95-percent control using a

longer averaging period. Commenters IV-D-20, IV-D-22, IV-D-31,

and IV-G-11 noted that, in the report, three fourths of the TEG

units controlled by condensers and flash tanks do not achieve a

95-percent reduction on an hourly basis. Commenters IV-D-27 and

IV-D-31 recommended that the EPA review the GRI report and adjust

the control efficiency and averaging time as appropriate.

 Based on the GRI study21, commenters IV-D-08, IV-D-10,

IV-D-15, IV-D-20, IV-D-22, IV-D-34, and IV-G-11 were concerned

that to achieve 95-percent control on a continuous basis,

additional combustion controls would be necessary. Commenter

IV-D-10 referred to the supplementary information in which the

EPA mentions that flares and other combustion devices were not

included in the MACT floor analysis because they do not recover

hydrocarbons. The commenter agreed that an after condenser

combustion device would waste nonrenewable resources for the sake

of peaks in ambient temperatures. Commenter IV-G-11 also noted

that many operators would install flares or incinerators rather

than reroute vapors to the firebox (due to safety issues and

State opacity regulations). Furthermore, commenters IV-D-10 and

IV-D-15 were concerned that the combustion device would force

operators to make tradeoffs among emissions of NOx, VOC, and HAP. 

Commenter IV-D-10 stated that combustion devices increase

emissions of NOx and VOC with greater dispersion impacts for only

5 percent additional HAP control on warm days and that the MACT

floor is not achievable with the technology envisioned.
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Commenter IV-G-12 stated that they collaborated several

years ago in an investigation of an evaporatively (water) cooled

condenser at one of its facilities that showed the condenser

could capture a significant portion (>90%) of the volatile

fraction coming from the still vent of a dehydrator. According

to the commenter, these condensers are easy to operate, provide

significant control, and result in the recovery and conservation

of a useful hydrocarbon stream. The commenter was concerned that

the proposed rule's presumed short term requirement of 95-percent

efficiency will preclude the use of devices of this type. The

commenter stated that the makeup of the gas being processed

determined the type of control that can be used. The commenter

suggested that facilities that can use a condenser should be able

to do so at a lower efficiency than required for flares operating

on equipment where condensers are not viable.

Commenter IV-D-21 provided emission reduction data resulting

from tests on dehydrators equipped with R-BTEX condensers. 

According to the commenter, the tests showed 96 to 98 percent VOC

and HAP emission reductions, at ambient wet bulb temperatures

ranging from 65 to 85oF. The commenter stated that while they

are confident that these condensers could achieve a 95-percent

control efficiency on an annual basis, they were concerned that

brief periods of high ambient temperatures would result in lower

control efficiencies. To account for the impact of ambient

temperature, the commenter requested that the EPA establish an

averaging time during which the average condenser outlet

temperature must comply with the requirements proposed in

§§63.773 and 63.1283.

Commenters IV-D-08 and IV-D-20 objected to the EPA's

suggestion that continuous compliance with a standard is

necessary to protect human health and the environment from

emissions from this source category. Commenter IV-D-20 urged the

EPA to retract this statement as unsupported and inconsistent

with other regulatory programs. The commenter suggested that the

industry is sensitive to unnecessary control costs, and urged the

EPA to reconsider this requirement. Commenters IV-D-08 and
22Reference 20.

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IV-D-20 stated that continuous monitoring as required in

§63.773(d) is not necessary because a monthly average compliance

demonstration does not increase emissions. Commenter IV-D-22

indicated that a rolling 12-month average compliance

demonstration would not result in significant increases in annual

emissions. Commenter IV-D-22 recommended that periodic

monitoring be substituted at an interval appropriate to the

condenser averaging period.

Commenter IV-G-07 stated that year-to-year variations in

annual temperature histograms are small and that using an annual

temperature histogram to calculate annual emissions is an

excellent proxy for any year. Furthermore, the commenter

maintained that there is not a good proxy for any day. The

commenter stated that Congress's focusing on annual emissions in

the Clean Air Act Amendments (CAAA) of 1990 set forth a good

regulatory policy and asked why should this policy be changed.

Commenters IV-D-08, IV-D-10, IV-D-15, IV-D-20, IV-D-22,

IV-D-34, IV-G-03, and IV-G-11 stated that for units with existing

condensers that do not quite achieve 95-percent reduction, the

incremental cost to remove a small increment of HAP emissions is

cost prohibitive. Commenters IV-D-20 and IV-D-22 stated that the

marginal cost to remove a small increment of HAP emissions to

achieve 95-percent control on a continuous basis would exceed

$ 20,000/ton of HAP removed. Commenters IV-D-34 and IV-G-11

estimated this cost to be $ 30,000/ton.

Response: Based on the information available to the Agency,

the EPA believes that the control devices required by the final

rule achieve 95-percent HAP emission reduction on a daily basis. 

However, the EPA has reviewed the GRI reports regarding condenser

performance22 and has considered the commenters concerns

regarding averaging periods for condensers. Based on this

information, the Agency has included an option for owners and

operators that install condensers.
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Under the final subpart HH [§63.772(f)], an owner or

operator of a glycol dehydration unit subject to the control

requirements under final §63.765 must demonstrate compliance with

the control device performance requirements on a daily basis. As

an alternative, the owner or operator that uses condensers to

comply with the requirements of §63.765 has the option of

demonstrating compliance with the 95-percent HAP emission

reduction on a 365-day rolling average [§63.772(g)]. An owner or

operator with less than 120 days of condenser operating data is

not required to calculate the average condenser efficiency until

after the first 120 days of operation. If this average

efficiency is equal to or greater than 90 percent, the owner or

operator is in compliance. Owners or operators with 120 days or

more, but less than 365 days of condenser operating data, must

calculate the average condenser efficiency over the number of

days of operation between the current day and the applicable

compliance date [specified in §63.760(f)]. The owner or operator

is considered to be in compliance with the performance

requirements if this average condenser efficiency is equal to or

greater than 90 percent. Once the owner or operator has 365 days

of condenser operating data, the owner or operator must comply

with the 95 percent HAP emission reduction requirement on a

365-day rolling average.

For glycol dehydration units in the natural gas transmission

and storage source category, the EPA believes that an averaging

period shorter than 365 days is appropriate. To the Agency's

knowledge, glycol dehydration units located at storage facilities

do not typically operate throughout the year. Additionally,

glycol dehydration units located at these sources do not

typically operate during the warm summer months when condenser

efficiency is lower. The data for the GRI report was based on

the operation of production facilities. 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 transmission facilities are used for withdrawing
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natural gas from storage (i.e., are not likely to operate yearround). Therefore, the final subpart HHH specifies that owners

or operators that install condensers have the option of complying

with the 95-percent HAP emission reduction on a 30-day rolling

average [§63.1282(f)]. However, §63.1282(f)(2)(iii)(D) of final

subpart HHH provides the owner or operator with the option of

complying with the 365-day rolling average procedure specified in

§63.772(g) for glycol dehydration units in the natural gas

transmission and storage source category that are operated

continually. 

2.10.3 Process Vent Standards

Comment: Commenter IV-D-08 stated that §63.771(d) should be

modified to provide credit for total reductions and cumulative

efficiency rather than requiring "control upon control"

efficiency. The commenter recommended changes to

§63.771(d)(1)(i), (ii), and (iii) to allow cumulative reductions

for control devices in series:

Reduce or contribute to the reduction of the mass

content of either Total Organic Compound (TOC) or total

HAP by 95 percent, from the point that gases are vented

to the first control device until the point that gases

are vented to the atmosphere.

Commenter IV-D-06 requested that subpart HHH expressly allow

combinations of control devices as a way to achieve the emissions

standards. According to the commenter, it may take two or more

control devices to achieve the emission limit. For example, some

units are controlled by devices that may come close to, but do

not meet the requirements. The commenter stated that it is

sometimes quicker, easier, and less expensive to add a

supplemental device than to remove an existing device and install

another. The commenter suggested using HON §§63.113(a)(2)(i),

(ii), and (ii)(A), (B), (C), and (D) to address combinations of

control and/or recovery devices. The commenter stated that if

subpart HH does not expressly allow combinations of control

devices, this comment applies to subpart HH.

Response: The EPA agrees that owners or operators should be

able to comply with the requirements of §§63.765 and 63.1275
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using combinations of control devices. Therefore, the EPA has

modified subparts HH and HHH to allow an owner or operator to

connect glycol dehydration unit process vents to a control device

or a combination of control devices [§§63.765(b)(1) and

63.1275(b)(1)]. In addition, the EPA has modified §63.772(e)(3)

of final subpart HH and §63.1282(d)(3) of final subpart HHH to

require the sampling sites to be located at the inlet of the

first control device and at the outlet of the final control

device.

Comment: Commenters IV-D-06, IV-D-07, IV-D-08, IV-D-20,

IV-D-22, and IV-D-30 requested that the EPA allow any

combinations of controls and process modifications to achieve the

required control efficiency. Commenters IV-D-08, IV-D-20,

IV-D-22, and IV-D-30 recommended that the EPA modify

§63.765(c)(2) to add language specifically stating that process

modifications and controls are allowed. 

In addition, commenter IV-D-30 suggested that the EPA

specify in §63.765(c) that the owner or operator may elect to

complete a compliance demonstration once for the required process

modifications. According to the commenter, no more demonstration

should be necessary if the owner or operator made only process

modifications (i.e., without emissions controls) to attain the

control efficiency and there are no further process

modifications.

Response: Proposed subparts HH and HHH contained provisions

allowing the owner or operator to demonstrate a 95 percent HAP

emission reduction using process modifications. The EPA did not

intend to preclude owners or operators from using combinations of

process modifications and control devices. Therefore, to clarify

that owners or operators have the option of using combinations of

process modifications and control devices, §§63.765(c)(2) and

63.1275(c)(2) of the final rules are as follows:

(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
2-135

modifications and one or more control devices, in

accordance with the requirements specified in

§63.771(e) [for subpart HH and §63.1281(e) for subpart

HHH].

The EPA does not agree with commenter IV-D-30's recommendation to

allow a one-time compliance demonstration. The EPA does not

believe that a one-time compliance demonstration would ensure

future or continuous compliance. Therefore, the EPA has not

included the commenter's suggested language. Instead, the final

rules contain provisions that require owners or operators to: 

(1) establish and document glycol dehydration unit baseline

operations; (2) document the conditions for which the glycol

dehydration unit baseline operations will be modified to achieve

a 95 percent overall HAP emission reduction using process

modifications or a combination of process modifications and one

or more control device; (3) maintain records demonstrating that

the facility operates under the conditions of the process

modification; and (4) if a control device is used in combination

with the process modifications, demonstrate that the control

device achieves the emission reduction required for an overall

emission reduction of 95 percent [§§63.771(e) and 63.1281(e)]. 

Only modifications in glycol dehydration unit operations directly

related to process changes (such as glycol recirculation rate or

glycol-HAP absorbency] are allowed. Changes in gas inlet

characteristics or natural gas throughput rate are not allowed to

be used as process modifications.

Comment: Commenter IV-D-05 stated that the requirement in

§63.765(c) to reduce emissions from the reboiler vent and flash

tank by 95 percent was ambiguous because the flash tank should

not be vented. According to the commenter, all of the offgas

from the flash tank should be recovered, and that GLYCalc assumes

this. The commenter suggested that §63.765(c) should be

clarified to state that ". . . HAP from a glycol process should

be reduced to 95 percent as compared with HAP without any process

modifications." The commenter noted that the term "process

modifications" would have to be defined, and the EPA would have

to address whether a flash tank is a process modification.
2-136

Commenter IV-D-05 also recommended that the definition of

GCG separator in subpart HH should state that all off-gas must be

recovered. The commenter also stated that the gas-condensateglycol (GCG) separator should not be called a tank since it is a

pressurized vessel.

Response: Although the GCG separator is a pressurized

vessel the industry commonly refers to it as a flash tank. For

example, the GCG separator is labeled as a flash tank in the TEG

dehydration flowsheet presented in GLYCalc. Therefore, the EPA

has not modified the definition of GCG separator in subparts HH

and HHH.

The EPA does not agree with the commenter's statement that

all off-gas must be recovered and that GLYCalc assumes that all

off-gas is recovered. According to the GLYCalc Dehydration

Handbook, contained electronically within the GLYCalc program,

the flash gas from the GCG separator can be used as a

supplemental fuel gas or as stripping gas in the reboiler, but

may be vented to the atmosphere at some locations. In addition,

the emission calculation in GLYCalc plainly separates flash gas

emissions from the GCG separator from the reboiler vent

emissions.

Although the EPA has not modified the definition of GCG

separator in response to this comment, the EPA believes that the

requirements in §§63.765(c)(3) and 63.1275(c)(3) need to be

clarified. As proposed, §§63.765(c)(3) and 63.1275(c)(3) stated

that control of HAP emissions from the flash tank ". . . is not

required if the owner or operator demonstrates to the

Administrator's satisfaction, that total HAP emissions to the

atmosphere from the glycol dehydration unit reboiler vent and GCG

separator (flash tank) are reduced by 95 percent." These

requirements were intended to provide owners and operators the

flexibility to install a control device to control emissions from

the reboiler vent such that the emission reduction from the

glycol dehydration unit process vent (which is defined in

§§63.761 and 63.1271 to include the flash tank and the reboiler

vent) is equivalent to 95 percent. Thus, the owner or operator
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would not be required to install separate control devices for the

reboiler and flash tank vents. Therefore, the EPA has modified

§§63.765(c)(3) and 63.1275(c)(3) to clarify this intent as

follows:

(3) Control of HAP emissions from a GCG separator

(flash tank) vent is not required if the owner or

operator demonstrates, to the Administrator's

satisfaction, that total HAP emissions to the

atmosphere from the glycol dehydration unit reboiler

process vent and GCG separator (flash tank) vent are

reduced by 95 percent one of the levels specified in

paragraphs (c)(3)(i) through (c)(3)(ii) of this

section, through 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.

Comment: Commenter IV-G-07 suggested an alternative MACT

rule based on air-cooled condensers: 

1. Stream exiting an air-cooled glycol dehydrator vent

condenser shall be in vapor/liquid equilibrium at or below a

temperature of 70oF or within ten Fahrenheit degrees of the

then current air temperature, averaged over any 24-hour

period.

2. Air emissions shall be less than: 5 tons/yr of benzene, 15

tons per year of HAP, and 50 tons per year of VOC.

3. A rich glycol flash tank must be used in any glycol

dehydration system, where its use will cause that system's

vent condenser to condense and recover more than an

additional 10 tons per year of VOC.

The commenter claimed that the proposed alternative: would

eliminate safety hazards associated with forcing operators to

burn some vent streams; is technically sound and cost effective;

and is good public policy by encouraging hydrocarbon recovery. 

The commenter claimed that the health risk concerns due to higher

emissions on hot days from air cooled condensers are not really

the problem, since in reality, hot daytime atmospheres are

unstable resulting in vent emissions becoming well mixed. 

According to the commenter, cool, still nights are a higher

potential exposure risk, which is small in any event.
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Response: Section 112 of the Act requires the EPA to

establish standards no less stringent than the MACT floor. As

stated in the previous response, the EPA determined that a

control efficiency of 95 percent represented the MACT floor. The

EPA does not believe that the commenter's suggestions represent

the MACT floor.

Comment: Commenter IV-D-07 interpreted §§63.765(c)(2) and

(3) and §§63.1275 (c)(2) and (3) to mean that emissions from both

the reboiler vent and flash tank vent can be used in determining

the emission reduction. The commenter supported this option.

Response: The commenter has correctly interpreted the

requirements specified in §§63.765(c)(3) and 63.1275(c)(3).

Comment: Commenter IV-D-07 stated that the EPA should

consider the fact that still vent and flash gas streams can be

laden with water and their use as a fuel source may not be

possible. The commenter suggested that burning these streams

would not be possible for smaller or unmanned facilities since

additional natural gas may need to be added to the stream before

flaring. Additionally, according to the commenter, the stream

composition may be inconsistent, and its use as a fuel or in a

flare may need to be closely monitored.

Response: Combustion of still vent and flash gas streams is

not required by subparts HH and HHH. It is up to the owner or

operator to decide whether combustion is a viable alternative for

control. In the final subparts HH and HHH, an owner or operator

has the option of complying with: (1) a HAP emission reduction of

95 percent or more; (2) an outlet HAP concentration of 20 ppmv or

less (for combustion devices) or (3) a benzene emission limit of

1 tpy. Therefore, the owner or operator should decide which

control device to use to comply with the required reductions

depending on individual stream characteristics.

2.10.4 Equipment Leak Standards

Comment: Commenter IV-D-05 requested that §63.769(a) be

clarified if the EPA intends to include ancillary equipment at

production facilities, and suggested the following wording: 

"This section applies to: (1) ancillary equipment at natural gas
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processing plants, and to (2) compressors (as defined in 63.761)

at natural gas processing plants that . . . " The commenter also

requested that the EPA justify the fact that this program does

not afford the same leniency as subpart KKK for plants that

process less than 10 MMscf/d regarding routine monitoring.

Response: The commenter is incorrect in stating that

subpart HH does not afford the same leniency as subpart KKK for

plants that process less than 10 MMscf/d. On the contrary,

§63.769(c)(5) exempts equipment located at nonfractionating

plants with the capacity to process 10 MMscf/d from routine

monitoring requirements, and is consistent with §60.633(d) of

subpart KKK. The metric capacity that is equivalent to

10 MMscf/d should be 283,000 standard cubic meters per day

(m3/day), rather than the proposed 283 m3/day. This has been

corrected in the final rule.

With regard to the commenter's first request, the EPA has

made the following change to clarify applicability to §63.769(a):

(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, ancillary equipment and compressors (as

defined in §63.761) at natural gas processing plants

that contain or contact a fluid (liquid or gas) that

has a total VOHAPVHAP concentration equal to or greater

than 10 percent by weight (determined according to the

provisions of 40 CFR 61.245(d) procedures specified in

§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 §63.761;

and

(2) Compressors.

Comment: Commenter IV-D-06 recommended that the EPA revise

§63.769(a) to apply only to equipment operating in VOHAP service

for 300 hours or more per year. According to the commenter, if

the equipment is in operation more than 300 hours per year, but

is in VOHAP service for only a small part of the time, there

would be no need for standards to apply.

Response: The EPA agrees with the commenter, and has

modified §63.769(a) in response to this comment to clarify that
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equipment operating in VHAP service for more than 300 hours per

year is subject to the rule.

Comment: Commenter IV-D-16 stated that it is confusing to

point to 40 CFR part 61, subpart V, which is unfamiliar to gas

plant operators, when subpart V is almost the same as 40 CFR part

60, subpart KKK. The commenter recommended that subpart HH point

to subpart KKK, since the regulated community and compliance

inspectors are familiar with it and will understand it better. 

The commenter also noted that the MACT floor is subpart KKK.

Response: The EPA determined that the MACT floor for

equipment leaks is subpart KKK and the NSPS level of control in

subpart KKK is equal to that of 40 CFR part 61, subpart V. 

However, subpart KKK is a standard that controls VOC and

subpart V controls HAP. Since the pollutants targeted for

control under subpart HH are HAP, cross-referencing the

requirements from the equipment leaks NESHAP (40 CFR part 61,

subpart V) is appropriate. 

Comment: Commenters IV-D-20 and IV-D-22 recommended that it

would be less burdensome and would avoid redundancy if provisions

were added, for facilities that are subject to other federal,

State, and local LDAR programs, to allow control of equipment

leaks under similar programs. Commenter IV-D-20 urged the EPA to

allow for a process of equivalency and/or stringency

demonstration for these other requirements. The commenter also

urged the EPA to clarify that facilities have the option of

complying with only one rule that will subsume all other LDAR

requirements. Furthermore, the commenter requested that §63.769

be expanded to allow for other equivalent, or more stringent

State, and local LDAR programs/rules to be used instead of

subpart HH requirements, provided the governing rule is

specifically included in the facility's title V permit. 

Commenter IV-D-22 endorsed the proposed provisions intended to

prevent duplication of effort and requirements for facilities

subject to LDAR requirements in part 63, subpart H, or subpart

KKK NSPS.
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Response: The EPA believes that facilities subject to other

federal, State and local regulatory programs should be allowed to

comply with the requirements those programs, if they are at least

as stringent, or equivalent to subparts HH and HHH. Sections

63.777 and 63.1287 already contain provisions for alternative

emission limitations that must be at least as equivalent as

subpart HH or HHH as appropriate. 

2.10.5 Control Device Requirements

Comment: Commenters IV-D-06, IV-G-02 and IV-G-12 stated

that §§63.771(d)(5) and 63.1281(d)(5) should only require that

spent carbon be managed as a hazardous waste if it is, in fact, a

hazardous waste. According to the commenters, it is not a listed

waste, so unless it displays a hazardous characteristic, it

should not have to be managed as a hazardous waste. Commenter

IV-D-06 recommended that the EPA should allow the option of

managing the carbon in a combustion device regulated under any

subpart of part 60, 61, or 63. The commenter stated that this

comment may also apply to subpart HH. Further, regarding

acceptable treatment methods, commenters IV-G-02 and IV-G-12

recommended the words "for which the owner or operator" be

changed to "whose owner or operator" to make clear that it is the

treatment facility, and not the generator, who must obtain the

proper RCRA permits or interim status.

Response: The EPA agrees with the commenters and has

replaced proposed §§63.771(d)(5) and 63.1281(d)(5) with the

following:

(5) For each carbon adsorption system used as a

control device to meet the requirements of paragraph

(d)(1) of this section, the owner or operator shall

manage the carbon as follows:

(i) Following the initial startup of the control

device, all carbon in the control device shall be

replaced with fresh carbon on a regular, predetermined

time interval that is no longer than the carbon service

life established for the carbon adsorption system.

(ii) All carbon removed from the control device

shall be managed in one of the following manners:The

spent carbon removed from the carbon adsorption system

shall be either regenerated, reactivated, or burned in
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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

either been issued a final permit under 40 CFR part

270, and designs and operates the unit in accordance

with that implements the requirements of 40 CFR 264,

subpart X; or certified compliance with the interim

status requirements of 40 CFR 265, subpart P. (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 hazardous air pollutants under

another subpart in 40 CFR part 61 or 40 CFR part 63.

(D) Burned in a hazardous waste incinerator for

which the owner or operator has been issued a final

permit under 40 CFR part 270, and designs and operates

the unit in accordance with that implements the

requirements of 40 CFR 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.

(C)(F) Burned in a boiler or industrial furnace

for which the owner or operator has either been issued

a final permit under 40 CFR part 270, and designs and

operates the unit in accordance with 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, or has certified compliance with the

interim status requirements of 40 CFR part 266, subpart

H.

2.10.6 Storage Vessel Standards

Comment: Commenter IV-D-16 stated that external floating

roofs complying with subpart Kb need to be addressed in the

storage vessel standard, if they are allowed. Commenter IV-D-22

stated that the proposed definition of cover in §63.761 includes

an external floating roof as an example; however, storage vessel

standards in §63.766 do not list external floating roofs as an

allowed control option. In fact, the commenter noted that

§63.766(b)(1) suggests that an external floating roof would need

to be connected through a closed-vent system to a control device. 

The commenter stated that they do not believe the EPA intended
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this result, because other existing standards, such as the

subpart Kb New Source Performance Standards (NSPS) (40 CFR

Section 60.110b), allow the external floating roof alone. The

commenter also stated that they do not endorse the detailed

control requirements in subpart Kb (for external or internal

floating roofs) for exploration and production (E&P) storage

tanks. In particular, the provisions in subpart Kb for the many

vents, fittings, lids, and other equipment on both internal and

external floating roofs are inappropriate for oil exploration and

production tanks. According to the commenter, it is not

appropriate to implement controls on E&P tanks that are more

stringent than the controls for tanks in a refinery and it is not

supported by the MACT floor for production tanks. Additionally,

the commenter noted that subpart Kb does not apply to the small

vessels typically located at production facilities.

Response: The EPA did not intend to limit the types of

covers allowed to only those listed as examples in the definition

of cover in §63.761. Therefore, the EPA has added language to

the definition of cover in §63.761 as follows: "...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."

The EPA's data, collected from section 114 questionnaires

and site visits indicated that the control technology in use to

control existing storage vessels did not include internal or

external floating roofs. Therefore, the EPA has removed the

requirements for internal floating roofs contained in proposed

§63.766(b)(3). However, in order to allow owners or operators

the option of complying with the requirements specified in 40 CFR

part 60, subpart Kb, 40 CFR part 63, subpart G, or 40 CFR part

63, subpart CC the EPA has added the following paragraph to

§63.766:

(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.
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2.11 MONITORING, RECORDKEEPING, AND REPORTING

Comment: Commenters IV-D-08, IV-D-22, and IV-D-34 requested

that the EPA allow oversized control devices to be exempt from

monitoring, inspection, recordkeeping and reporting requirements

other than the initial design analysis. The commenters stated

that oversized devices will essentially always meet the

regulatory requirements. According to the commenters, if a

design analysis shows that the device is oversized so that

compliance with the control efficiency requirement will be met

even during worst case conditions, the exemption should be

allowed. The commenters explained that an exemption would allow

the owner or operator to spend more on the device and less on

monitoring, inspection, recordkeeping, and reporting over the

life of the facility. The commenters further stated that is it

not cost-effective to continue monitoring, inspection,

recordkeeping, and reporting for a device that will always meet

regulatory requirements.

Response: Monitoring, inspection, recordkeeping and

reporting requirements ensure continuous compliance with the

standards. Over-designing a control device would not ensure

proper operation and compliance with the standards. Therefore,

the EPA has not modified subparts HH and HHH in response to these

comments.

Comment: Commenters IV-D-20 and IV-D-22 urged the EPA to

reevaluate how the monitoring, recordkeeping, and reporting

requirements can be made clear, nonoverlapping, and implementable

in the field. According to the commenters, the "cut and paste"

approach apparently used by the EPA to develop the monitoring,

recordkeeping, and reporting requirements leads to a burdensome

set of confusing, and sometimes unnecessary, requirements. 

Commenter IV-D-22 stated that they believe the proposed

monitoring, recordkeeping, and reporting requirements impose a

significant burden on E&P facilities that cannot be justified

based on any current monitoring, recordkeeping, and reporting for

oil or gas facilities.
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Commenter IV-D-09 noted that §§63.10(b)(2) and 63.10(c)

require 24 separate record entries for each dehydration unit and

control device, as well as up to seven separate reports. The

commenter stated that many of these reports are superfluous. As

an example, the commenter suggested consolidating all information

required to ensure the operational status of the monitoring

system into one combined maintenance and operational log. The

commenter also requested that the EPA work with operators to

explore ways to incorporate the information required for

compliance demonstrations into existing recordkeeping and

reporting practices realistically.

Response: 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.

In response to the commenters' concerns, 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 final rules (subparts HH and HHH) 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 submitted along with the summaries of the results

of other tests.

(3) Site-specific test plans describing quality assurance

in §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).

(4) A reduction in the record retention requirements for

monitored parameters. The proposal required values of monitored
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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.

Comment: Commenter IV-D-38 suggested that §63.764(c) be

modified as follows so that affected sources that are not at

major HAP sources do not have to meet stringent control,

monitoring, and recordkeeping requirements:

(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 HAP source shall

comply with the standards in this subpart as specified

in paragraphs (c)(1) through (c)(3) of this section.

Response: A major source is defined in §63.2 as "any

stationary source" that "emits, or has the potential to emit, 

. . . any hazardous air pollutant." Although the EPA believes

that specifying that affected sources are located at existing or

new major HAP sources would be redundant, the EPA has made the

suggested modification.

2.11.1 Monitoring Requirements

Comment: Commenter IV-D-01 questioned the basis for the

10,000 ppm leak definition in §63.769(c)(2) and requested that

the 10,000 ppm leak definition for pressure relief devices in

gas/vapor service be changed to 500 ppm. The commenter stated

that the pressure relief devices in gas/vapor service should have

a leak definition of 500 ppm above background in accordance with

40 CFR 61.242-4(a).

Commenter IV-D-01 also requested that the EPA delete the

provision for which pressure relief devices, in a

nonfractionating facility monitored only by non-facility

personnel, may be monitored after a pressure release the next

time the monitoring personnel are on-site, instead of within five

days (not to exceed 30 days following a pressure release without

monitoring). The commenter stated that the owner or operator

could make provisions for either company personnel or contract

personnel to perform the monitoring. The commenter also stated

that pressure release devices should be monitored no later than
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five calendar days after each pressure release in accordance with

40 CFR 61.242-4(b)(2).

Response: Currently, the oil and natural gas production

industry is regulated by the NSPS for equipment leaks of VOC from

onshore natural gas processing plants (40 CFR part 60, subpart

KKK). The EPA determined that the MACT floor for equipment leaks

at natural gas processing plants was the NSPS level of control. 

Subpart KKK requires owners and operators to monitor pressure

relief devices quarterly and within five days after each pressure

release to detect leaks [§63.633(b)(3)], with a leak defined as

an instrument reading of 10,000 ppm or greater [§60.633(b)(2)]. 

Section 61.242-4(a) requires pressure relief devices to be

operated with no detectable emissions, which is more stringent

than subpart KKK. Since the MACT floor was determined to be

equivalent to the level of control specified in subpart HHH, the

EPA has not changed the leak definition for pressure relief

devices, as requested by the commenter.

The requirement allowing the owner and operator of a

nonfractionating facility, which are monitored only by

non-facility personnel, to monitor after a pressure release the

next time the monitoring personnel are on-site is consistent with

40 CFR part 60, subpart KKK [§63.633(b)(4)]. Since the MACT

floor was determined to be the level of control required by

subpart KKK, the EPA has not made the change suggested by the

commenter.

Comment: Commenter IV-D-22 recommended that the EPA allow

for a deviation from a 2 percent leak rate during startup,

shutdown, or malfunction, per the facility startup, shutdown and

malfunction plan, as specified in §63.10(d)(5), without forgoing

the option for skip monitoring. Although subpart HH does not

mention skip monitoring directly, the commenter stated that they

believe it is invoked through the reference to the leak detection

and repair (LDAR) work practice standard in 40 CFR part 60,

subpart VV. [Note: The commenter's citation is incorrect. 

Subpart HH refers to 40 CFR part 61, subpart V.]
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Response: The purpose of the startup, shutdown, and

malfunction (SSM) plan is to ensure that owners and operators

operate and maintain affected sources with good air pollution

control practices at all times. The SSM plan also ensures that

owners or operators are prepared to correct malfunctions quickly,

to minimize excess HAP emissions. The EPA believes that

monitoring is warranted during SSM, however, the EPA has modified

§63.774(b)(3) to state that the leaks that occur during SSM

events do not count toward the percent leak rate, provided the

SSM plan is followed.

Comment: Several commenters were concerned with the

provisions specifying the accuracy of the measurement devices

used to comply with the subpart. Commenter IV-D-06 recommended

that the EPA allow measurement devices with better accuracy than

what subpart HHH requires. The commenter contended that the way

subpart HHH was written, using devices with better accuracy than

the rule specifies is forbidden. The commenter suggested that

the EPA revise the following sections and paragraphs to allow

more accurate measuring devices. The commenter noted that there

may also be other paragraphs (in particular, they did not look

closely at the compliance demonstration requirements) and if so,

the EPA should revise them similarly to the examples shown below.

Section 63.1271:

Temperature monitoring device means a unit of

equipment used to monitor temperature and having an

minimum accuracy of + 1 percent of the temperature

being monitored expressed in oC, or + 0.5oC, whichever

is greater.

Section 63.1282(a)(1)(i):

(i) The owner or operator shall install and

operate a monitoring instrument that directly measures

flow to the glycol dehydration unit with an accuracy of

plus or minus 2 percent or better.

Section 63.1283(d)(3)(i)(A), (B), (D), (E), and (F):

(A) For a thermal vapor incinerator, a temperature

monitoring device equipped with a continuous recorder. 

The monitoring device shall have an minimum accuracy of

+1 percent of the temperature being monitored in oC ,or

+0.5 oC, whichever value is greater. The temperature
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sensor shall be installed at a location in the

combustion chamber downstream of the combustion zone.

(B) For a catalytic vapor incinerator, a

temperature monitoring device equipped with a

continuous recorder. The device shall be capable of

monitoring temperature at two locations and have an

minimum accuracy of +1 percent of the temperature being

monitored in oC, or +0.5 oC, 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.

(D) For a boiler or process heater with a design

heat input capacity of less than 44 megawatts, a

temperature monitoring device equipped with a

continuous recorder. The temperature monitoring device

shall have an minimum accuracy of +1 percent of the

temperature being monitored in oC, or +0.5 oC,

whichever value is greater. The temperature sensor

shall be installed at a location in the combustion

chamber downstream of the combustion zone.

(E) For a condenser, a temperature monitoring

device equipped with a continuous recorder. The

temperature monitoring device shall have an minimum

accuracy of +1 percent of the temperature being

monitored in oC, or +0.5 oC, whichever value is

greater. The temperature sensor shall be installed at

a location in the exhaust vent stream from the

condenser.

(F) For a regenerative-type carbon adsorption

system, an integrating regeneration stream flow

monitoring device equipped with a continuous recorder,

and a carbon bed temperature monitoring device equipped

with a continuous recorder. The integrating

regeneration stream flow monitoring device shall have

an minimum accuracy of +10 percent and measure the

total regeneration stream mass flow during the carbon

bed regeneration cycle. The temperature monitoring

device shall have an minimum accuracy of +1 percent of

the temperature being monitored in oC, or +0.5 oC,

whichever value is greater and measure the carbon bed

temperature both after the regeneration and within 15

minutes of completing the cooling cycle, and over the

duration of the carbon bed steaming cycle.

The commenter stated that this comment also applies to subpart

HH.
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Response: The EPA agrees with the commenter's

recommendation to modify the monitoring device accuracy

specifications to state that the accuracy requirements are the

minimum necessary to demonstrate compliance and has modified the

subparts HH and HHH as suggested.

Comment: Commenters IV-D-08 and IV-D-22 requested that the

EPA require flow instrumentation with an accuracy of +2 percent

only when the measured values are within 98 percent of the

exemption or compliance targets. The commenters stated that

while this level of accuracy is available, proving compliance for

streams that do not have flows close to the exemption or

compliance levels is not necessary. Commenter IV-D-22 stated

that throughout §63.773, subpart HH refers to temperature

monitoring devices with an accuracy of + 1 percent of the

temperature being monitored in oC, or +0.5 oC, whichever value is

greater. The commenter, along with commenter IV-D-08, stated

that they do not believe that the MACT floor for this source

category supports the accuracy of 2 percent for measuring flow

and 1 percent for measuring temperature, or that they have

demonstrated continuous compliance with applicable standards. 

Commenter IV-G-12 also stated that the +0.5 oC measurement is

practically useless for many analog temperature recorders. 

Commenter IV-D-22 stated that requiring a unit to demonstrate

compliance with a temperature requirement is unnecessary and

unduly restrictive unless the operator chooses to select a

temperature set point within 1 percent of the requirement. The

commenter recommended, and commenter IV-D-34 supported, that

subpart HH be modified to eliminate specified accuracies for flow

and temperature measurement devices and to allow whatever

accuracy is necessary to demonstrate compliance with the

temperature or flow target.

Response: The average emission limitation achieved by the

top 12 percent of the facilities (for source categories with more

than 30 facilities) has to be considered for the MACT floor for

existing sources. The EPA believes that accuracy requirements

are necessary to demonstrate ongoing compliance. The EPA also
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believes setting site-specific accuracy requirements would be

unduly burdensome for the permitting agencies. In addition, a

minimum accuracy provides an advantage for the owner or operator

because they would not be required to use the same monitor

forever. 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, to provide

additional flexibility in selecting monitoring devices, 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.

Comment: Commenters IV-D-22 and IV-D-34 recommended that a

provision be added to allow design analysis or engineering

calculations in place of monitoring if they can demonstrate that

limits will not be exceeded.

Response: Allowing design or engineering calculations would

show theoretical compliance, but would not demonstrate continuous

compliance with the emission standard. The EPA believes that the

monitoring requirements in subparts HH and HHH are the minimum

necessary to ensure compliance with the standards. Therefore,

the EPA has not added the provisions recommended by the

commenters.

Comment: Commenter IV-D-06 recommended that the EPA clarify

the bypass monitoring requirements. The commenter stated that

§63.1281(c)(3)(i)(A) says flow indicators must indicate "whether

gas, vapor, or fume flow is present" at least once every 15

minutes. The commenter suggested that the wording seems to

require a direct indication of "flow." The commenter requested

that the definition of "flow indicator" be revised to allow valve

position indicators. The commenter stated that valve position

indicators will not give a reading of whether flow is present,

but they will give a reading of whether a diversion has occurred. 

In addition, the commenter noted that §63.1281(c)(3)(i)(B) says

that car-seals are intended to show that valves are in the
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"closed" position. The commenter provided an example of a

three-way valve that is commonly used in bypass situations. 

According to the commenter, three-way valves have two "open"

positions and one "closed" position. In those cases, the valve

should be car-sealed in the open position that goes to the

control device. The commenter felt that the literal wording of

subpart HHH does not allow that option. The commenter

interpreted the wording to read that the "closed" position is

required. The commenter suggested the following changes to

§63.1281(c)(3)(i)(A) and (B). 

(A) Install, calibrate, maintain, and operate a

flow indicator at the inlet to the bypass device that

indicates takes a reading at least once every 15

minutes whether gas, vapor, or fume flow is present in

the bypass device; or

(B) Secure the valve installed at the inlet to the

bypass device in the closed 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 closed

non-diverting position.

The commenter stated that this comment also applies to subpart

HH.

Response: The EPA believes that clarifications to the

bypass requirements are necessary to allow valve position

indicators, and to require that a car-seal be used to secure a

valve installed at the inlet to the bypass device in the

non-diverting position. The EPA has modified §§63.771(c)(3)(i)

and 63.1281(c)(3)(i) as follows:

(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 indicates 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 atmospherewhether gas, vapor, or

fume flow is present in the bypass device; or

(B) Secure the bypass device valve installed at

the inlet to the bypass device in the closed

non-diverting position using a car-seal or a

lock-and-key type configuration. The owner or operator
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shall visually inspect the seal or closure mechanism at

least once every month to verify that the valve is

maintained in the closed non-diverting position and the

vent stream is not diverted through the bypass device.

In addition, the final rules contain a definition of flow

indicator in §§63.761 and 63.1271.

The EPA has also added recordkeeping and reporting

requirements for the bypass line requirements. The final rules

contain recordkeeping requirements [§§63.774(b)(4)(iii) and (iv)

and 63.1284(b)(4)(iii) and (iv)], which require an owner or

operator to maintain records of whether the flow indicator 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. When a seal or closure

mechanism is used, hourly records of flow are not required. In

such cases, the owner or operator is required to 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.

The final rule also requires owners or operators to include,

in the periodic reports, all periods when the vent stream is

diverted from the control device through a bypass line. When a

seal or closure mechanism is used, the periodic report must

contain all periods in which the seal mechanism was broken, the

bypass valve position was changed, or the key to unlock the

bypass line valve was checked out.

In addition, periods where the vent stream has been diverted

through the bypass line, as indicated by the flow indicator or

the closure mechanism or seal, are defined as excursions except

when they occur during startup, shutdown, or malfunction events

or periods of nonoperation.

Comment: Commenter IV-D-06 requested that the EPA revise

Table 2 to say that §63.8(e) does not apply to subpart HHH. The

commenter stated that subpart HHH does not require a performance
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evaluation at a specific time on a continuous monitoring system. 

Therefore, according to the commenter, if §63.8(e) applies,

nothing is required. The commenter further stated that various

other MACT standards have not required performance evaluations on

continuous monitoring systems. The commenter suggested that

imposing the burden of these performance evaluations is

unnecessary. The commenter stated that if subpart HH also

incorporates §63.8(e), then this comment also applies to subpart

HH.

Response: Although performance evaluations on continuous

monitoring systems are not specifically required under subparts

HH and HHH, the Administrator retains the authority to request

such evaluations. Therefore, the EPA has modified table 2 of 

subparts HH and HHH to state that the applicable subpart does not

specifically require continuous monitoring system performance

evaluations but that the Administrator can request the owner or

operator to conduct performance evaluations.

Comment: Commenter IV-D-31 requested that if the intent of

the monitoring protocol is to ensure that the equipment is

operating correctly, then subpart HHH should state that intent. 

The commenter also requested that the EPA consider the complexity

of the control equipment when designing a monitoring period. The

commenter suggested that the frequency of monitoring be based on

the probability of a device failing to function. The commenter

suggested that simple condenser systems cannot vary widely in

performance over short periods and have a minimum probability of

failure, meaning that recording information at frequent intervals

is inefficient and wasteful.

Response: The intent of the monitoring protocol is to

ensure compliance with the standards. Based on the comments

received on the proposed rules, the EPA reevaluated the

monitoring requirements contained in subparts HH and HHH. As

stated in section 2.10.2 of this document, the final rule

specifies that control devices must determine compliance using

the daily average of the monitored parameters. Owners and

operators that install condensers have the option of using a
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365-day average under final subpart HH and a 30-day average under

final subpart HHH. To reduce the number of data points required

to be used in these average calculations, the EPA has modified

the monitoring requirements for control devices. The final rule

requires continuous monitoring systems to measure data values at

least once every hour and record either each measured data value,

or each block average for each 1-hour period or shorter periods

calculated from all measured data values during each period.

Comment: Commenter IV-D-06 stated that components exempt

from instrumental leak detection monitoring in §63.1283(c)(3)

(such as components under a vacuum) should also be exempt from

the initial monitoring. The commenter stated that this comment

may also apply to subpart HH. Commenter IV-D-22 suggested that

the type of "no detectable emissions" monitoring required in

§§63.771(c)(2) and 63.773(c)(1)(ii) cannot be justified by a MACT

floor analysis.

Response: The EPA believes that initial monitoring is

necessary to show that the closed-vent system is has been

designed to operate with no detectable emissions. However, the

EPA believes that once closed-vent system components that are

permanently or semi-permanently sealed (e.g., welded joints) have

been shown to operate with no detectable emissions, future

monitoring is not necessary, unless components are repaired,

replaced or unsealed. Therefore, the final rule requires annual

visual inspections for these components to detect defects that

could result in air emissions. However, the final rule requires

closed-vent system components that are not permanently or

semi-permanently sealed to be monitored annually to demonstrate

that they are operated with no detectable emissions, in addition

to the initial inspection and the annual visual inspections.

Comment: Commenter IV-D-07 supported the EPA's statement

that "[t]he CMS that uses gas chromatography to measure

individual organic HAP compound chemicals is not practical for

applications where multiple organic HAP chemicals are to be

monitored . . . " According to the commenter, monitoring of

control devices should be flexible to allow for impracticalities
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in using CMS. Furthermore, the commenter supported the

monitoring of control device operating parameters' performance

for compliance demonstrations.

Response: The EPA appreciates the commenter's support. As

stated in the preamble to the proposed rules (63 FR 6307), the

EPA rejected the use of continuous emission monitoring systems

(CEMS) for two reasons: (1) CEMS that use gas chromatography to

measure individual gaseous organic HAP are not practical for use

when multiple HAP are monitored, and (2) CEMS that measure total

VOC or total hydrocarbons do not provide a quantified level of

the organic species present. Therefore, the EPA selected

parameters that would indicate air emission control performance

for the monitoring approach. The EPA believes that the selected

parameters are good indicators of control device performance and

continuous parameter monitoring instrumentation is available at a

reasonable cost.

Comment: Several commenters were concerned with the impact

of the monitoring requirements on remote and/or unmanned

facilities. The commenters suggested that lack of electricity,

instrument air, and personnel availability would cause problems

complying with the monitoring requirements. Commenter IV-D-08

stated that obtaining electricity for instrumentation necessary

to implement continuous monitors is expensive and burdensome for

remote facilities. Commenter IV-D-11 stated that their

facilities are located in the wetlands or in state waters and

pose unique problems. The commenter explained that many of these

locations are unmanned or are manned for a few hours per day and

access to most of these facilities is by boat and sometimes by

helicopter. The commenter also noted that the weather environment

is not conducive to maintaining sophisticated electronic

equipment that affects the cost of any control strategy imposed. 

According to the commenter, temperatures range from freezing in

the winter to the high 90's in the summer, with high humidity and

facilities near the coast experience corrosion problems from the

saltwater. 
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Response: 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.

Several of the facilities visited during the proposal during

the development of the proposal were remote and sometimes

unmanned facilities that operate through the use of automatic

control in monitoring systems. In particular, one site did not

have electrical lines to the site (II-B-2). Power was provided

by solar panels and associated storage batteries.

The EPA believes that monitoring devices are essential at

unmanned sites to ensure that control devices are operating to

ensure compliance and are the minimum necessary to ensure that

control devices are operating to ensure compliance. Therefore,

the EPA has not reduced the monitoring device requirements for

unmanned facilities.

Comment: Commenter IV-D-16 noted that most available,

reliable, accurate monitoring equipment requires electrical

power. The commenter recommended that §63.773(d) be amended to

allow for temperature indicators that do not record data. The

commenter suggested a compliance determination process: upon

inspection of the facility by a regulatory official, the

temperature indicator would be observed and the reading compared

with the value chosen for the control device. If this value is

unsatisfactory, the facility operator would be required to

perform a compliance test per §63.772(e). Compliance with the

applicable standard would be based on the result of the

compliance test.

Response: The purpose of a temperature indicator is to

ensure compliance with the standard. As stated in a previous

response, the EPA considered requiring continuous monitoring

systems that measure emissions. However, the EPA determined that

parametric monitoring systems would be less burdensome but would

be good indicators of control device performance. Furthermore,

monitoring device records provide inspectors a means for

determining whether or not a control device was operating in
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compliance. The EPA believes that temperature indicators that do

not record data would not give any indication of compliance over

the appropriate averaging period. Therefore, the EPA has not

modified the monitoring device requirements in response to this

comment.

Comment: Commenters IV-D-20, IV-D-22, and IV-D-34 requested

that the EPA amend §63.771(b) and (c) to require periodic visual

inspection rather than "no detectable emissions" for covers and

closed vent systems. Commenters IV-D-20 and IV-D-22 suggested

that repairs would be made if there was visual evidence of a

defect that could result in emissions. The commenters explained

that many E&P field operations have limited manpower and are

remote which prevents them from being attended daily. The

commenters stated that a "no detectable emissions" requirement

was inappropriate for exploration and production storage vessels

and requested that the requirement be dropped. According to the

commenters, the requirements would impose significant burdens on

the industry. Commenter IV-D-22 suggested that the type of "no

detectable emissions" monitoring required in §§63.771(b) and

63.773(b)(3)(ii) cannot be justified by a MACT floor analysis.

In addition, commenters IV-D-20, IV-D-22 and IV-D-34 stated

that removing material from a leaking tank until the leak is

repaired [as required in §63.771(b)(2)] would result in higher

emissions during the transfer operations than would be emitted if

the material was left in place. The commenters were concerned

that removing the material from the tank would require several

wells to be shut in and would risk reservoir damage. Commenters

IV-D-20 and IV-D-22 indicated that this requirement is

inconsistent with §63.773(b)(3)(vii), which allows the material

to remain in the tank if the leak cannot be repaired within 15

calendar days after the leak is detected. The commenters urged

the EPA to delete these provisions.

Response: The EPA has evaluated the requirements for

storage vessels in subpart HH and determined that the proposed

requirements were not appropriate for the oil and natural gas

industry. Therefore, the EPA has modified §63.771(b) as follows:
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(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 tankoperate

with no detectable emissions when all cover openings

are secured in a closed, sealed position. (2) The owner or operator shall determine that the

cover operates with no detectable emissions by testing

each opening on the cover in accordance with the

procedures specified in §63.772(c) the first time

material is placed into the unit on which the cover is

installed. If a leak is detected and cannot be

repaired at the time that the leak is detected, the

material shall be removed from the unit and the unit

shall not be used until the leak is repaired.

(32) Each cover opening shall be secured in a

closed, . . .

Additionally, the inspection and monitoring requirements

contained in proposed §63.773(b) have been combined with the

inspection and monitoring requirements for closed vent systems in

§63.773(c). Therefore, §63.773(c) of final subpart HH and

§63.1282(c) of final subpart HHH (Cover and closed-vent systems

inspection and monitoring requirements) specifies that covers

must be visually inspected following the installation of the

cover, and annually for defects that could result in air

emissions. 

In response to the commenters concern about the removal of

material from a leaking storage vessel, the EPA has revised the

requirements for the repair of leaks. The EPA believes that a

15-day period is sufficient to repair a leak. However, the EPA

has provided an option for a delay of repair if a repair is

technically infeasible without a shutdown, or if emissions from

the immediate repair would be greater than the fugitive emissions

resulting from the delay of repair. Therefore, §§63.773(c) and

63.1283(c) of the final rules specify that leaks from covers or

closed-vent systems that are detected during the periodic

inspections must be repaired no later than 15 days after the leak

is detected, unless a delay of repair is requested. In this

case, the repair must be completed by the end of the next

shutdown.
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Comment: Commenter IV-G-02 asked why §§63.771(d)(3)(i)(C)

and 63.1281(d)(3)(i)(C) exempt a vent stream introduced with the

primary fuel from performance test requirements. The commenter

questioned whether the EPA has data showing that, in oil and gas

production and natural gas transmission and storage facilities,

any boiler or process heater achieves a specific HAP reduction

efficiency, or that vent streams introduced with the primary fuel

are more likely to achieve reduction and do not need a

performance test. The commenter maintained that if the EPA does

not have HAP reduction data for boilers and process heaters in

this source category, the control should be a work practice for

which a performance test is unnecessary. The commenter cited

§63.644 of subpart CC (the petroleum refinery MACT) of 40 CFR

part 63 as a precedence for making the control for such vent

streams a work practice for which the monitoring requirement is a

certification that the stream is introduced into the flame zone

of the boiler or process heater.

Commenter IV-D-22 stated that §§63.771(d)(3)(i)(B) and

63.773(d)(2)(ii) exempt boilers or process heaters from

performance testing and monitoring if they have an input capacity

equal to or greater than 44 megawatts (MW). The commenter was

not aware of any fuel gas combustion devices in this source

category as large as 44 MW [(150 million British thermal units

per hour, (MMBtu/hr)]. The commenter stated that they appreciate

the EPA's attempt to reduce the compliance requirements for

certain situations, but this heat input threshold designation is

virtually meaningless for this source category. 

Commenter IV-D-35 referred to §63.771(d)(1)(i)(C), which

requires the vent stream to be introduced into the flame zone of

a boiler or process heater, and §63.771(d)(3)(i)(C), which

exempts boilers or process heaters from performance testing if

the vent stream is introduced with the primary fuel. The

commenter suggested that the wording in §63.771(d)(1)(i)(C) be

modified to require the vent stream to be mixed with the primary

fuel prior to introduction to the burner nozzles or injectors.

[Note: The reference in this sentence was §63.771(d)(3)(i)(C)
23 Hazardous Air Pollutant Emissions from Process Units in

the Synthetic Organic Chemical Manufacturing Industry -

Background Information for Proposed Standards. Volume 1B: 

Control Technologies. November 1992. EPA-453/D-92-016b. pg.

2-18.

2-162

but the context indicates that it should be §63.771(d)(1)(i)(C).

The commenter stated that boilers and process heaters that

introduce the vent stream through their own nozzles or injectors

should be subject to performance testing because the degree of

combustion being provided by the vent stream would be unknown

without performance testing.

Response: The EPA believes that the exemption for boilers

with an input capacity greater than 44 MW is important even if

only one boiler in the entire source category meets the

exemption. The EPA has not removed this exemption.

The EPA's information shows that boilers or process heaters

larger than 44 MW (150 MMBtu/hr) typically operate at

temperatures and residence times necessary to achieve 95-percent

reduction or greater (usually greater than 98 percent), while

boilers and process heaters smaller than 44 MW are frequently not

operated to achieve the 95-percent requirement. In addition,

analyses also show that when the vent streams are introduced into

the flame zone, over 95-percent reduction is achieved. This is

because the required residence time is decreased because of the

relatively high temperature and turbulence of the flame zone.23

Additionally, the final rules do not require an initial

performance test or monitoring for boilers or process heaters

with minimum heat inputs of 44 MW, or boilers and process heaters

smaller than 44 MW if the vent stream is introduced with the

primary fuel.

Comment: Commenter IV-G-09 disagreed with the requirement

in proposed §63.1282(d) that vent streams from dehydration

condensers must be measured for HAP even if the vent streams are

introduced with combustion air as secondary fuel. The commenter

suggested that the operator is being penalized for the

environmentally appropriate step of using these streams as
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secondary fuel and sampling data is meaningless. The commenter

requested that this requirement be removed. [Note: this comment

also applies to proposed §63.772(e).]

Response: The EPA does not agree with the commenter. As

stated in the previous response, the EPA's information indicates 

that for combustion units where the vent stream is introduced

into the flame zone with the primary fuel achieve at least a

95-percent emission reduction. Although it is possible for an

individual enclosed combustion device to achieve a 95-percent

emission reduction when the vent stream is introduced with the

combustion air as secondary fuel, the EPA does not have the test

data to support this and therefore, it is not appropriate to

ensure compliance. A design analysis is allowed as an

alternative to demonstrate compliance if the owner or operator

determines that a performance test is too burdensome. Therefore,

the EPA has not modified subparts HH and HHH in response to this

comment.

Comment: Commenter IV-D-22 stated that since proposed

§63.771(d)(3)(i)(A) exempts flares from performance testing,

combustion devices such as heater treaters and glycol reboiler

burners should also be exempt from performance testing.

Response: The final rules provide an option for owners and

operators to demonstrate compliance with the 95-percent HAP

emission reduction using a flare designed and operated according

to §63.11(b). Therefore, the final rule clarifies that only

flares designed and operated in accordance with §63.11(b) are

exempt from the performance test requirements. As stated in the

previous response, boilers or process heaters smaller than 44 MW

(e.g., heater treaters or glycol reboiler burners) are frequently

not operated to achieve a 95-percent emission reduction. 

Therefore, the EPA has not exempted heater treaters and glycol

reboilers from the performance testing requirements.

Comment: Commenter IV-D-22 noted that §63.773(d)(2) exempts

control devices from monitoring in which vent streams are

introduced with the primary fuel. The commenter suggested that

§63.773(d)(2)(i) should be clarified to provide that "introduced
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with the primary fuel" means "at the same location in the process

heater," such as the burner block, and does not require the vent

stream to be compressed and introduced into the primary fuel gas

line. No combustion or destruction efficiency advantage exists

from mixing the vent gas into the primary fuel line versus the

burner block because the vent gas undergoes the same residence

time and temperature history in either case. However,

significant additional cost is incurred to compress the vent gas

to introduce it in the primary fuel line instead of at the burner

block.

Response: The performance test and monitoring requirement

exemptions for boilers and process heaters for which the vent

stream is introduced with the primary fuel or as the primary

fuel, are consistent with the EPA's approach for several other

rules (e.g., the HON). The commenter did not provide technical

information to demonstrate that their recommendation would

provide an equivalent level of control warranting an exemption. 

Therefore, the EPA has not modified subparts HH and HHH in

response to this comment.

Comment: Commenter IV-G-02 noted that in the proposed

§63.769 standards for equipment leaks, there is no exemption in

paragraphs (c)(1) through (3) from monitoring for pressure relief

devices routed through a closed vent system to a control device

(such as a flare). According to the commenter, pressure relief

devices controlled in this way cannot be monitored as the section

requires. The commenter pointed to the equipment leaks NSPS

(40 CFR part 60, subpart VV), to which all NSPS for equipment

leaks (including subpart KKK) reference, which recognizes this

and provides an exemption [the commenter cited §60.482-4(c) and

§61.242-4(c)]. Since this proposal recognizes that equipment

complying with subpart KKK of part 60 must meet more stringent

standards and are exempt from meeting §63.769 requirements, the

commenter requested a similar exemption be included for units not

required to comply with the subpart KKK standards.

Response: The commenter's statement that §63.769 does not

contain monitoring exemptions for pressure relief devices routed
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through a closed-vent system to a control device is incorrect. 

According to §63.769(c), an owner or operator of ancillary

equipment and compressors subject to the equipment leak standards

of subpart HH must comply with the requirements of 40 CFR 61.241

through 247. Thus, the exemption contained in §61.242-4, for

pressure relief devices routed through a closed-vent system to a

control device, applies. Therefore, the EPA did not modify

subpart HH in response to this comment.

Comment: Commenter IV-D-14 asked whether the EPA would

place additional emphasis on compliance monitoring for "synthetic

minor sources" or minor sources near the major source threshold,

as has been seen during the implementation of the title V

program.

Response: The EPA is uncertain what the commenter means by

"additional emphasis on compliance monitoring for synthetic

minors," but notes that the final rules do not alter the part 70

requirements for monitoring of any applicable requirement at

title V sources.

2.11.2 Recordkeeping and Reporting Requirements

Comment: Two commenters were concerned with the relevance

of the records required by the standard. Commenter IV-D-05 noted

that glycol units that are exempt from the control standards are

only required to keep records of gas flow rates. Based on their

experience with the results of GLYCalc 3.0, the commenter stated

that glycol circulation rates and gas composition are more

critical parameters affecting emissions than gas flow rates.

Commenter IV-D-06 suggested that keeping records of glycol

dehydration unit design capacity (in terms of natural gas flow

rate to the unit per day) is not relevant. According to the

commenter, keeping records of the design capacity will not show

what the benzene emissions are, and will not really tell anything

about whether the unit qualifies for the one tpy exemption. The

commenter further stated that if the exemption was claimed based

on actual gas throughput being less than 3 MMscf/d, they could

understand a requirement to keep records of how actual gas input

was determined. However, the commenter stated that keeping
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records of design capacity would not document whether they

qualify for exemption since the exemption is based on actual gas

input rather than theoretical gas input.

Response: Maintaining records of glycol dehydration unit

natural gas flow rate is required to document that a source meets

the criteria for the throughput exemption under §§63.764(e), and

proposed 63.1274(b) [now codified under §63.1274(d)]. As

proposed, subparts HH and HHH did not require the owner or

operator to keep records for the benzene emission criteria for an

exemption under §§63.764(e), and 63.1274(b). These criteria are

necessary to document that the source qualifies for an exemption

from control requirements based on benzene emissions, therefore,

§63.774 of final subpart HH and §63.1284(d) of final subpart HHH

contain recordkeeping requirements for the benzene emission

criteria to document that the affected source qualifies for the

exemption. The final rule requires records of benzene emissions

determined either by emissions model or direct measurement for

these sources.

Comment: Several commenters were interested in reducing the

recordkeeping and reporting burden on affected sources. 

Commenter IV-D-32 recommended streamlining the recordkeeping

requirements, but did not provide any specific recommendations. 

Commenter IV-D-06 requested that the EPA allow a "reduced

recordkeeping" option, for monitoring data. The commenter stated

that the EPA should not impose a blanket requirement to retain

every monitored parameter data point, and that such a requirement

would impose a large paperwork burden with no environmental

benefit. The commenter stated that a compromise, such as the

"reduced recordkeeping" option, which would allow for the storage

of less data if the monitoring system has special enhancements

would be acceptable. The commenter recommended that the EPA use

the HON subpart G, §63.152(g) as a model. The commenter stated

that this comment also applies to subpart HH. 

Commenter IV-D-06 also stated that they support

§63.1285(b)(9) and (c) which say that no paperwork requirements

apply to certain exempt sources. The commenter supported the
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EPA's making steps toward reducing unnecessary paperwork burdens. 

The commenter stated that the same approach should be implemented

in all MACT standards.

Response: The reduced recordkeeping option recommended by

commenter IV-D-06 allows an owner or operator to retain only

daily averages of monitored parameter data if certain monitoring

device design criteria are met. In addition, these requirements

allow an owner or operator to not retain the daily average for

any operating day when the daily average is below the maximum

parameter limit, or above the minimum parameter limit (as

appropriate), provided 6 months have passed without an excursion. 

The EPA does not believe that the reduced recordkeeping option is

appropriate for the oil and natural gas production and natural

gas transmission and storage source categories. First, past

performance does not prevent future exceedances. Secondly, the

365-day averaging period option for condensers installed to

comply with subpart HH and the 30-day averaging period option for

condensers installed to comply with subpart HHH require owners or

operators to retain the daily average data to calculate the

appropriate average. Therefore the EPA has not incorporated the

reduced recordkeeping option into subparts HH and HHH.

However, the EPA did re-evaluate the recordkeeping

requirements and has reduced the number of data points required

to be measured and recorded for monitoring data. The final rules

require continuous monitoring systems to measure and record data

at least every hour, rather than every 15 minutes. The EPA

believes that this will significantly reduce the amount of data

generated by monitoring devices.

Comment: Commenter IV-D-06 stated that they do not support

a requirement to keep records proving entitlement to an

exemption, which takes away some of the value of the exemption. 

The commenter stated that since benzene emissions or gas input

can change with time, the records of a historic determination may

not say anything about current conditions. The commenter

maintained that they claim an exemption at their own peril. The

commenter contended that if, at any time, the benzene emissions
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or the annual average gas input exceeds the threshold, the

exemption would no longer apply. The commenter stated that this

comment may also apply to subpart HH.

Response: The EPA does not agree with the commenter. Since

the throughput and benzene emission values are annual averages,

some historical data is necessary. Furthermore, the EPA believes

that the exemption has significant value to justify keeping

records. Therefore, the EPA has not modified subparts HH and HHH

in response to this comment.

Comment: Two commenters were particularly concerned with

the onsite recordkeeping requirements. Commenters IV-D-06 and

IV-D-16 requested that the EPA provide for offsite storage of

records and revise Table 2 to say that §63.10(b)(1) does not

apply. The commenters stated that the requirement in

§63.10(b)(1) to store records on-site is not appropriate, as

facilities in remote locations would not have file storage space. 

Commenter IV-D-06 proposed that the records be collected

periodically and taken to a central location (such as the same

location where compliance personnel, who review the records and

prepare the reports, are located). The commenter recommended

that the EPA add a paragraph to the "recordkeeping" section of

subpart HHH expressly allowing offsite storage if the records are

readily accessible. The commenter stated that if subpart HH also

incorporates §63.10(b)(1), this comment also applies to subpart

HH. Commenter IV-D-16 suggested that by replacing the records

retention requirements with inspection by a regulatory official

followed by compliance testing (if necessary), the problem of

retaining records at gas production facilities would be avoided.

Response: The EPA does not believe that replacing the

record retention requirements with inspections followed by

compliance testing (if necessary) would allow inspectors readily

to determine compliance with these standards, at any source. 

However, the EPA agrees that owners and operators should be

allowed to retain some data off-site. Therefore, in response to

these comments, the EPA has modified the record retention

requirements in §§63.774(b) and 63.1284(b) as follows:
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C Owner or operator must retain the most recent 12 months of

records onsite or the records must be accessible from a

central location by computer or other means that provides

access within two hours after a request; C Owner or operator may retain the remaining four years of

records offsite; and C Owner or operator may maintain records in hard copy or

computer-readable form including, but not limited to, on

paper, microfilm, computer, floppy disk, magnetic tape, or

microfiche.

Comment: Commenters IV-D-08, IV-D-22, and IV-G-03 requested

that the EPA merge several reports into one package to be

delivered to the regulatory agency. According to the commenters,

the merged reporting approach prevents multiple, staggered

reports from being generated and transmitted without providing a

comprehensive picture on compliance status. The commenters

recommended that the EPA:

C allow for reports to be merged through a title V mechanism

for title V facilities;

C merge redundant reports;

C create a unified list of reports; and

C limit frequency to no more than semiannually.

Commenters IV-D-22 and IV-D-34 recommended that the EPA

amend §§63.774 and 63.775 to allow operators to maintain annual

documentation of State or federally enforceable limits, and to

require reports only as necessary based upon the specific device

or operating limit relied upon for emission control. The

commenters urged the EPA to use the same recordkeeping and

reporting requirements as 40 CFR 63 subpart CC (refinery rule) as

follows:

C allow semiannual or annual reports rather than reporting

events as they occur;

C allow the permitting authority and operator to determine

which information will be reported or simply documented; and

C eliminate duplication for facilities subject to multiple

requirements.

The commenters suggested that this would ensure compliance while

reducing the burden on the operators and permitting agency.

Response: The EPA recognizes that unnecessary monitoring,

recordkeeping, and reporting requirements would burden both the

source and the enforcement agencies. As stated in an earlier

response at the beginning of section 2.11 of this document, the
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final rules contain only monitoring, recordkeeping, and reporting

requirements that are necessary to demonstrate compliance.

State and local agencies have the option of enforcing

different, but equivalent, monitoring, recordkeeping, and

reporting requirements if they submit information on their

program to the EPA for approval under the procedures for

delegation of NESHAP authority under section 112(l) of the CAA.

Furthermore, in cases where reporting requirements of State

or local rules duplicate those of subparts HH or HHH, a source

can work with their State or local title V permit authority to

avoid duplicate submittals.

In response to the commenters' request to limit the

reporting frequency, table 2 of the final rule has been changed

to indicate that the requirement specified in §63.10(e)(3)(i)(C),

for quarterly reporting in cases where monitoring parameters are

out of range or monitors are not operating more than a specified

percent of the time, does not apply. Instead, semiannual

reporting is required for all facilities. As proposed,

facilities were required to report semiannually, but if the

source experienced excess emissions, quarterly reports would be

required.

This change was made because the EPA agrees that the

quarterly reporting system proposed added complexity to the rule,

it may not be helpful for enforcement, and that penalties for

noncompliance are a sufficient disincentive for poor performance. 

Further, semiannual reporting is consistent with title V

operating permit reporting requirements. Requiring separate

quarterly reports for some facilities adds complexity and

increases the reporting burden for both the facility and the

enforcement agency. Semiannual reports will provide the

regulatory agency information on excess emissions within about

six months of the occurrence. This is well within the 1-year

period in which the agency can take administrative enforcement

actions as specified under section 113(d) of the CAA.

Comment: Commenters IV-D-07 and IV-G-03 requested an

adjustment for the reporting requirements for unmanned
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facilities, as the reporting requirements seemed unnecessarily

burdensome. Commenter IV-D-07 requested monthly recordkeeping

and annual reporting.

Response: As stated in the previous response, sources can

discuss with the implementing agency the possibility of

submitting different reports, providing these reports are

equivalent.

Annual reporting was not selected as requested by the

commenters, because it would significantly reduce the EPA's

ability to take administrative enforcement actions. Section

113(d) of the CAA limits the assessment of administrative

penalties to violations that occur no more than 12 months prior

to the initiation of the administrative proceeding. Periodic

reports are a primary means of identifying possible violations,

and annual submittal would not give the enforcement agency time

to review the report and take action on a violation that occurred

early in the reporting period within one year after the event.

Comment: Commenters IV-D-08, IV-D-22, and IV-D-26 stated

that requiring initial notifications within one year is not

realistic. The commenters referred to the Gasoline Distribution

Terminals and Pipeline Breakout Stations standard (subpart R)

which comprises many different sized facilities. According to

the commenters, the initial assessments have taken more than one

year and the EPA has had to amend subpart R to allow the

facilities more time. Therefore the commenters, along with

commenter IV-D-32, recommended the following:

C extend the initial notification period to at least two

years;

C create a tiered notification requirements; and

C allow a single notification to cover multiple facilities in

the same region.

Response: The information required in the initial

notification includes basic facility information, such as name

and address, physical location, identification of the standard

that is the basis of the notification, a facility description,

and a statement of whether the source is a major or area source. 

The EPA believes that all of this information, except the major
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or area source determination, should be readily available. 

Facilities that are potentially subject to subparts HH and HHH

have been aware that they might have to perform a major source

determination since the date of the proposed rule (February 6,

1998). Furthermore, by the time the initial notification is due

(assuming an effective date of May 15, 1999), these facilities

will have had more than 27 months from the proposal date to

determine their major source status. The EPA believes that there

is ample time to make this determination.

However, the EPA has modified §§63.775 and 63.1285 for

affected sources that are major on or before the date the initial

notification is due (one year after the effective date of the

regulation), that plan to become area sources by the compliance

date. The final rule states that these affected sources that are

major sources but plan to become area sources must include in the

initial notification, a brief, nonbinding description of a

schedule for the actions that are planned to achieve area source

status.

Nothing in subparts HH and HHH prevents single notifications

for multiple facilities, provided the required information for

all facilities is contained in the notifications.

Comment: Commenters IV-D-08 and IV-D-22 were concerned that

the wording in §63.9(h) might be misunderstood, as far as when

the notification of compliance status is required, or how soon it

has to occur after promulgation. The commenters recommended the

following:

C establish a certain time for Notification of Compliance

Status -- 180 days after promulgation, as provided for in

§63.9(h)(2)(ii); and

C reference specific sections in subpart A for the required

contents of this notification (i.e., §63.9(h)(2)(i)).

Response: The EPA agrees that it would be more clear if the

due dates for the notification of compliance status were stated

explicitly in the rule. In addition, the EPA has included

several sections from the General Provisions (40 CFR part 63,

subpart A) directly in subparts HH and HHH. Sections 63.775(d)
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of final subpart HH and §63.1285(d) of final subpart HHH contain

the Notification of Compliance Status Report requirements.

Comment: Commenter IV-D-01 requested that the reporting of

the number of components monitored be a requirement of semiannual

reports. The commenter noted that the reporting requirements in

§61.247(b), for each piece of ancillary equipment subject to

§63.769, do not require the number of components monitored per

reporting period to be included in each semiannual report. The

commenter stated that the number of components is required in 40

CFR 63 Subpart H. The commenter cited the benefits for including

the number of components:

1. Facilitates more rapid review of the report;

2. Provides verification of percent leakers; and

3. Ensures that the facility continues to monitor all

components.

Response: The EPA agrees with the commenter that the number

of monitored components is important to verify the calculation of

the percent leakers and to ensure that a facility continues to

monitor all components. Therefore, §63.775(d)(3) of the final

rule contains requirements for owners and operators subject to

§63.769 to submit the information required under §61.247(a) (of

40 CFR, part 61, subpart V), except for the following:

C The initial report required in §61.247(a) must be submitted

as a part of the Notification of Compliance Status Report

required under subpart HH.

C The number of each equipment (e.g., valves, pumps, etc.)

must be included in the Notification of Compliance Status

Report.

C Changes in the information submitted in the Notification of

Compliance Status Report must be submitted in subsequent

Periodic Reports.

Comment: Commenter IV-D-01 requested that the EPA delete

the reporting requirement exemption [§63.775(b)(9)] for sources

that are not subject to the control requirements for glycol

dehydration unit process vents. The commenter stated that these

sources may still be subject to the storage vessel and equipment

leak provisions and they must also conduct performance tests and

develop startup, shutdown and malfunction plans. The commenter
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further stated that since these facilities are not exempt from

recordkeeping requirements, reporting would "hardly constitute an

excessive burden."

Response: The intent of the reporting requirements

contained in proposed §63.775(b)(9) of subpart HH and

§63.1285(b)(9) of subpart HHH was not to exempt entire

facilities, but to exempt glycol dehydration units that are not

subject to the control requirements, as specified in proposed

§§63.764(e) and 63.1274(b) [now codified at §63.764(e)(1) of

subpart HH and §63.1274(d) of subpart HHH], from the reporting

requirements. To clarify this intent, the final rules specify

that only the units exempt from the control requirements are

exempt from the reporting requirements in subpart HH and HHH

[codified at §63.775(b)(7) of subpart HH and §63.1285(b)(7) of

subpart HHH]. Thus, the reporting requirement exemptions do not

apply to other units within the facility that are subject to the

rule, including glycol dehydration units, storage vessels, and

ancillary equipment. 

Similarly, §63.764(e)(3) of final subpart HH specifies that

ancillary equipment and compressors that contain or contact fluid

with a VHAP concentration less than 10 percent and that are in

VHAP service less than 300 hours per year are exempted from the

control requirements of §63.769. Therefore, §63.775(b)(8) of the

final rule contains an exemption from the reporting requirements

for ancillary equipment and compressors that are not subject to

§63.769. 

Additionally, it should be noted that although storage

vessels with the potential for flash emissions (as defined in

§63.761) are not subject to the recordkeeping and reporting

requirements, an owner or operator would be required to maintain

records for these sources under §63.10(b)(3) of 40 CFR part 63,

subpart A, which contains recordkeeping requirements for

applicability determinations.

Comment: Commenter IV-D-06 stated that §63.1285(b)(7) does

not specify a deadline for reports on equipment that was

initially exempt, but becomes subject to control requirements due
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to process changes. The commenter requested reasonable deadlines

for these reports. The commenter stated that this comment may

also apply to subpart HH. 

Response: The EPA agrees that provisions are necessary for

area sources that become major sources due to increases in HAP

emissions or increases in PTE. Therefore, the final rules 

specify the following:

C compliance dates for area sources that become major sources

[§63.760(f) of subpart HH and §63.1270(d) of subpart HHH], C initial notification requirements for area sources that

become major sources which are correlated to the compliance

dates [§63.775(b)(1) of subpart HH and §63.1285(b)(1) of

subpart HHH], and C notifications of process changes due within 180 days after

the process change or by the next Periodic Report, whichever

is sooner [§63.775(f) of subpart HH and §63.1285(f) of

subpart HHH].

Comment: Commenter IV-D-16 recommended that startup,

shutdown and malfunction reports as required under §63.10(d)(5)

should not be required under subpart HH. The commenter did

suggest that if they are required, the startup, shutdown, and

malfunction reporting requirements should only apply to gas

plants, and should be part of the semiannual reports required by

title V rather than a stand alone report.

Response: The startup, shutdown, and malfunction report

enables the EPA to keep track of excess emissions and harm to the

environment, and is only required if the owner or operator does

not follow their startup, shutdown, and malfunction plan. 

Therefore, the EPA believes that these reports must be submitted

within seven days of the malfunction. If the owner or operator

is thorough in developing their facility's startup, shutdown, and

malfunction plan, and ensures that the plan is followed during

startup, shutdown, and malfunction events, these reports will not

be necessary. However, it should be noted that the final rule

states that separate startup, shutdown, and malfunction reports

are not necessary if the required information is included in the

Periodic Report for the facility [codified at §63.775(b)(6) of

subpart HH and §63.1285(b)(6) of subpart HHH].
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2.12 TEST METHODS

Comment: Commenter IV-D-06 stated that Methods 1 or 1A will

usually not be appropriate as required in §63.1282(d)(1). 

According to the commenter, Method 1 is only for large stacks and

Method 1A is for smaller stacks, and continual references

throughout Method 1A say the method is for particulate. The

commenter stated that they would not generally be dealing with

particulate under subpart HHH. The commenter recommended that

§63.1282(d)(1) be revised to say that "if we use Method 1A, any

references to particulate do not apply." The commenter stated

that this comment may also apply to subpart HH. 

Response: The procedures outlined in Methods 1 and 1A are

to be used only to select a sampling site. However, to clarify

the EPA's intent, the final rules state that Method 1 or 1A of 40

CFR part 60, appendix A must be used to select the sampling site,

and any references to particulate mentioned in Methods 1 and 1A

do not apply [codified at §63.772(e)(3)(i) of subpart HH and

§63.1282(d)(3)(i) of subpart HHH].

Comment: Commenter IV-D-06 stated that the EPA should

revise §63.1283(c)(3) to require Method 21 "with the differences

specified in §63.1282(b) of this subpart." The commenter stated

that it was confusing that §63.1282(b) specified a modified

Method 21 and §63.1283(c)(3) specified "straight" Method 21. The

commenter stated that according to §63.1282(b), something like

modified Method 21 should be used. The commenter stated that

this comment may also apply to subpart HH. 

Response: The EPA agrees with this recommendation and has

modified the closed-vent system requirements [now codified at

§63.773(c)(2)(i) and (ii) of subpart HH and §63.1283(c)(2)(i) and

(ii) of subpart HHH] to reference the no detectable emissions

procedure under §63.772(b) of subpart HH and §63.1282(b) of

subpart HHH.

Comment: Commenter IV-D-09 was concerned with the emissions

test procedures requirement to use Method 18 to determine

concentrations and emissions of HAP and TOC. The commenter

stated that although Method 18 is appropriate for speciating
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organic HAP, it is not appropriate for speciating TOC. The

commenter explained that Method 18 uses gas chromatography (GC)

to separate a variety of organic compounds. According to the

commenter, individual peaks could vary widely in resolution,

depending on the complexity of the sample. The commenter further

explained that the error associated with determining TOC by GC

could be substantial as it would reflect the sum of several

errors associated with the separation and detection of individual

organic compounds. Furthermore, the commenter expressed doubt

that any one chromatographic column and set of operating

conditions will cleanly separate the complex organic matrix

present in dehydration units.

The commenter recommended that the EPA either require use of

Method 25A for determining TOC or allow the use of Method 25A as

an alternative means of determining TOC. According to the

commenter, the analytical error associated with discrepancies

between the response factor of the calibration gases used in

Method 25A and the average response factor of the organic gas

matrix will not be as significant as the errors associated with

Method 18. The commenter further recommended that alternate

calibration schemes could be used to ensure safety, if the EPA is

concerned with FID response factors. Specifically, the commenter

suggested that since the FID response factor in Method 25A is

retarded by the presence of oxygenated or chlorinated compounds,

the EPA could specify that the FID at the outlet of a combustion

control device be calibrated with a mixture of methanol in air. 

According to the commenter, "since methanol has a relatively high

oxygen-to-carbon ratio, it will have among the most markedly

dampened response factors of any organic compound likely to be

present in the air stream."

The commenter stated that allowing the use of Method 25A

would reduce the cost associated with emissions testing. 

According to the commenter, Method 18 costs approximately two to

three times more than Method 25A because Method 18 requires the

use of more sophisticated laboratory techniques. Additionally,

the commenter noted that since Method 18 does not result in more
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accurate TOC emissions estimates, there is not an environmental

benefit associated with an increased cost.

Response: The EPA agrees with the commenter. The aromatic

compounds contained in the vent stream make method 25A an

appropriate method for measuring TOC. The final rules allow the

owner or operator the option of using either method 18 or method

25A [codified at §§63.772(e)(3)(iii) and 63.772(e)(3)(iv) of

subpart HH and §§63.1282(d)(3)(iii) and 63.1282(d)(3)(iv) of

subpart HHH].

Comment: Commenter IV-D-07 requested that the EPA specify

how emissions from the combustion source should be measured. 

According to the commenter, Method 25 does not differentiate

between methane, ethane, and VOC, and furthermore, testing grab

samples with a GC/MS tends to be inaccurate. The commenter also

asked whether the 20 ppmv concentration limit is measured "as

propane" or "as methane." 

Response: Proposed §§63.772(e)(3) and (4) of subpart HH and

§§63.1282(d)(3) and (4) of subpart HHH [now codified at

§§63.772(e)(3)(iii) and (iv) of final subpart HH and

§§63.1282(d)(3)(iii) and (iv) of final subpart HHH] state that

emissions from combustion sources must be measured using Method

18, 40 CFR part 60, appendix A, or any other method or data

validated according to the applicable procedures in Method 301,

40 CFR part 63, appendix A. As mentioned in the previous

response, the EPA has also modified the test method requirements

to allow the owner or operator the option of using Method 25A,

instead of Method 18.

When using Method 18, the 20-ppmv concentration limit is

determined as the sum of the compound concentration as measured

by Method 18. Individual compounds are presented as the compound

(e.g., benzene concentration would be presented as 5 ppmv as

benzene). If using Method 25A, the measurement should be

presented based on the calibration gas used.

Comment: Commenter IV-G-01 remarked that the proposed

NESHAP states that bagging is the only method for measuring

fugitive hydrocarbon emissions. The commenter stated that the
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High Volume Collection System has been demonstrated to be as

effective as the bagging method, as shown in EPA-600/R-95-167.

Response: Although the High Volume Collection System could

be an alternative method for measuring fugitive HAP emissions,

the EPA determined that the MACT floor for equipment leaks from

ancillary equipment and compressors in the oil and natural gas

production source category was the level of control required

under 40 CFR part 60, subpart KKK. Therefore, the equipment leak

standards are based on work practices and operational practices

equivalent to those required under subpart KKK, rather than

emission standards.

Comment: Commenter IV-G-15 provided a letter from a

technical consultant to the commenter that describes how EPA

Methods 0030/5040 Volatile Organic Sampling Train (VOST) can be

used with some modification to characterize accurately emissions

from glycol dehydration units. The consultant described the

modified method as the new "Bag VOST" technique, similar to

California Air Resources Board Method 422.

Commenter IV-G-16 and commenter IV-G-15 provided proposed

sampling procedures for glycol dehydration units. According to

the commenters, the proposed procedures would be used to estimate

uncontrolled emissions and control efficiency for units

controlled with condensers, and are based on EPA Methods 1, 2,

3B, 4, and 18 modified. The commenters stated that gas samples

are collected over a one hour period. The commenters referred to

the method of analysis as GC/FID and GC/TCD.

Commenter IV-D-03 provided for the EPA's information, a copy

of the paper entitled Flash Vaporization Emissions Test Method

for Storage Tank VOC & HAP, which was presented at the October

1997 EPA/A&WMA Emission Inventory Conference in RTP, NC. The

commenter stated that the paper describes the EquiVapTM test

method and its ability to quantify accurately and speciate

storage tank emissions based on fundamental thermodynamic

principles using cost effective conventional labware and software

analytical tools. 
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Response: In order for the EPA to approve alternative test

methods, the Agency must receive an analysis according to the

procedures in 40 CFR part 60, appendix A, Method 301. Additional

guidance for obtaining EPA approval for alternate test methods

and procedures may be found on the Internet at:

http://www.epa.gov/ttn/emc. 

Comment: Commenter IV-G-02 noted that §63.772(a) appears to

be in conflict with §63.769(a). The commenter explained that

§63.772(a) sets out a complicated procedure using Method 305 or

Method 25D to determine the HAP content of material for

applicability of equipment leak standards and §63.769(a) requires

the use of the method in §61.245(d) (incorporating ASTM Method

D-2267). The commenter requested a clarification that either

method can be used to give owners and operators maximum

flexibility to choose most economical method available to them.

Response: The EPA agrees that proposed §63.769(a) and

§63.772(a) are inconsistent. The test method specified in

§61.245(d), ASTM Method D-2267, is no longer considered by the

EPA to be a valid test method. Therefore, the EPA has modified

§63.769(a) in the final rule as follows:

". . . that contains or contacts a fluid (liquid or

gas) that has a total VOHAPVHAP concentration equal to

or greater than 10 percent by weight (determined

according to the provisions of 40 CFR

61.245(d)procedures specified in §63.772(a)) . . . "

In addition, the EPA evaluated the procedures for determining

VHAP concentration for the applicability to the equipment leak

standards under proposed §63.772(a) and determined that the

procedures were not appropriate for the oil and natural gas

production source category. The EPA believes that Method 18 of

40 CFR part 60, appendix A and the procedure specified in 40 CFR

63.180(d) of this part are appropriate for determining the VHAP

concentration of fluid contained in or in contact with ancillary

equipment or compressors. Therefore, §63.772(a) of the final

subpart HH reads as follows:

(a) Determination of material VHAP or HAP

concentration to determine the applicability of the

equipment leak standards under this subpart (§63.769).
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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.

Comment: Commenter IV-D-06 requested that the EPA clarify

"background level" issues, for instrumental leak detection

monitoring. The commenter referred to §63.1282(b)(5), which

requires that the procedures in Method 21 should be used to

determine background levels. However, the commenter stated that

Method 21 does not have any procedures to determine background

levels. According to the commenter, Method 21 says how to

monitor for concentrations of certain substances. Additionally,

the commenter recommended that the EPA clarify whether or not

there is an option to either determine background level. The

commenter stated that the regulatory burden would be reduced and

the environment would actually be benefitted by not determining a

background level. The commenter suggested that the EPA use the

current version of the HON subpart H, §63.180(c) and (c)(2). The

commenter stated that this comment also applies to subpart HH.

Response: The EPA does not agree with the commenter's

statement that Method 21 does not contain procedures to determine

background emission levels. In fact, section 4.3.2 of EPA Method

21 is a section for determining local ambient concentrations (40

CFR part 60, appendix A, Method 21, §4.3.2), which is the

methodology for determining background emission concentrations. 

The EPA agrees that an option for determining background

emissions is appropriate. Therefore, §63.772(c)(5) of final
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subpart HH and §63.1282(b)(5) of final subpart HHH provide the

owner or operator the option of not determining background

emissions. However, it should be noted that if an owner or

operator chooses not to determine background emissions, and

Method 21 shows emissions greater than 500 ppmv, the equipment

will not be in compliance.
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2.13 COMPLIANCE

2.13.1 Compliance Procedures

Comment: Commenter IV-D-22 recommended that subpart HH

include a provision allowing for delay of repair in the event the

repairs cannot be made on-line and a unit shutdown will be

required. The commenter recommended a provision similar to the

provision in 40 CFR §63.171(a), referenced in the Refinery MACT

rule [40 CFR §63.648(c)], which allows for delay of repair if the

repairs require a shutdown.

Response: Proposed §63.769(c) states that the owner or

operator of ancillary equipment must "meet the requirements

specified in 40 CFR 61.241 through 61.247 . . . , " including

the provisions contained in §61.242-10, allowing for a delay of

repair if the repair cannot be made on-line and a unit shutdown

would be required. Therefore, the equipment leak standards of

subpart HH already contain the provisions requested by the

commenter.

Comment: Commenters IV-D-18 and IV-D-25 stated that the

procedure specified in §63.772 corrects the measured outlet

concentration of HAP to 3 percent oxygen. According to the

commenters, many thermal and catalytic oxidizers properly operate

with oxygen levels in the exhaust stream near 20 percent and the

correction to 3 percent oxygen would make the concentration-based

limit unnecessarily restrictive. Therefore, commenter IV-D-25

recommended that §63.772(e)(4) be changed to reflect that the

concentration of TOC shall be corrected to the designed oxygen

content in the outlet stream and the equation in

§63.772(e)(4)(iii)(B) should be modified accordingly.

Response: Section 63.771(d)(1)(i)(B) (control requirements)

provides an option requiring combustion devices to reduce "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 . . . . " To make a direct comparison between the

enclosed combustion device total HAP concentration limit

specified in §63.771(d)(1)(i)(B), and the TOC or total HAP
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emissions measured using the procedures specified in §63.772(e),

a correction to 3 percent oxygen is necessary. Without this

correction, a direct comparison of measured emissions to the

concentration limit would not be possible. Therefore, the EPA

does not see any reason to modify §63.772(e)(4) or the equation

contained in proposed §63.772(e)(4)(iii)(B) [now codified at

§63.772(e)(3)(iv)(C)(2) of the final rule] in response to this

comment.

Comment: Commenter IV-D-35 requested that the alternative

condenser evaluation allowed in §63.1282(e) specify that the

liquid streams to be sampled are before and after the condenser,

to avoid any confusion regarding the testing before and after the

still or reboiler. [Note: this comment also applies to

§63.772(f)].

Response: The commenter's request that proposed §63.1282(e)

specify that the liquid sample streams are "before and after the

condenser" is incorrect. The GRI report entitled "Atmospheric

Rich/Lean Method for Determining Glycol Dehydrator Emissions"

(GRI-95/0368.1) specifies the following sample point locations

for collecting rich and lean glycol samples:

1. Rich Glycol: select a sample point between the glycol

pump and the reboiler.

2. Lean Glycol: select a sample point between the

reboiler and the contactor, if a charcoal filter is not

in line between the reboiler and the contactor, OR

between the reboiler and the charcoal filter, if a

charcoal filter is between the reboiler and the

contactor.

Therefore, the sample locations are required to be before and

after the reboiler, not before and after the condenser.

The EPA's intent was for the ARL methodology specified in

the GRI report to be used in conjunction with GLYCalc to

determine condenser performance. To clarify this intent,

proposed §§63.772(f) and 63.1282(e) [now codified at

§63.772(e)(5) of final subpart HH and §63.1282(d)(5) of final

subpart HHH] have been modified to specify that the ARL method

can be used to provide inputs for use in conjunction with

GLYCalc.
24Memorandum from Jones, L.G., U.S. EPA/Emissions

Measurement Branch, to J.D. Mobely, U.S. EPA/ Emission Factor and

Inventory Group. "Glycol Dehydrator Emissions Test Report and

Emissions Estimation Methodology." April 13, 1995.

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Comment: Commenter IV-G-07 supplied a detailed 

"engineering assessment" methodology for calculating annual HAP

and VOC emissions from condenser-controlled dehydration units

(for possible use in emissions reporting). This method would

use: (1) GLYCalc to estimate uncontrolled emissions, (2) a

process design model (e.g., Hysim, Aspen, PD+, etc.) to estimate

emissions as a function of condenser outlet temperature, (3) a

curve of emissions vs. ambient air temperature, constructed based

on a condenser design that produces an outlet vapor/liquid stream

in equilibrium at least ten degrees Fahrenheit above ambient

temperature, and (4) National Climatic Data Center temperature

data for the station nearest the site to construct an annual dry

bulb temperature histogram. Annual emissions would be calculated

by integrating the emissions vs. air temperature curve over the

temperature histogram.

Commenters IV-G-15 and IV-D-16 described models that exist

for estimating emissions from glycol dehydration units. 

According to the commenters, GLYCalc, written by Radian

Corporation, and PROSIM, written by Bryan Research and

Engineering, are approved by the TNRCC. A third model written by

OPC DRIZO, is used for design purposes by OPC, but is not

available to the public. The consultant made the statement that

the emissions models used generally underestimate the actual

emissions generated, and that nothing beats a good stack test.

Response: The EPA reviewed the information supplied by the

commenters. The EPA evaluated GLYCalc from GRI as a tool for

estimating emissions from glycol dehydration units24 and the EPA

recommends the use of this model for the development of emission

inventories to meet Clean Air Act requirements. The EPA

understands that the program may overestimate emissions from

these units, but believes that the use of accurate input data

will reduce this potential.
2-186

Proposed §§63.771(d)(3)(iv) and 63.1281(d)(3)(iv) [now

codified at §63.772(e)(4) of final subpart HH and §63.1272(d)(4)

of final subpart HHH] contain specific requirements for design

analyses which may be used to demonstrate compliance with the

control device performance requirements. The commenters'

suggested approaches are acceptable, provided they comply with

the requirements for condenser design analyses as specified in

final §63.772(e)(4)(i)(D) or §63.1282(d)(4)(i)(D). It should be

noted that any disagreements between the owner or operator and

the Administrator would be resolved by conducting a performance

test as specified in final §§63.772(e)(4)(ii) or

63.772(d)(4)(ii). The EPA has not added guidance for estimating

emissions, for reporting, to the final rules. However, the EPA

will publish implementation guidance following promulgation of

subparts HH and HHH.

Comment: Commenter IV-D-07 interpreted §63.1282(d)(1)(i)(A)

to mean that the sampling site must be located upstream of the

control device. The commenter also suggested that the EPA

include a definition for the term final product recovery device.

Response: The control device inlet sampling site must be

located at the inlet of the first control device. To clarify,

the EPA has modified proposed §§63.772(e)(1)(i)(A) and

63.1282(d)(1)(i)(A) [now codified at §§63.772(e)(3)(i)(A) and

63.1282(d)(3)(i)(A)] as follows:

(A) . . . inlet sampling sites shall be located at

the inlet of the first control device and at the outlet

of the final control device.

A recovery device is one used for recovering chemicals for

fuel value, use, reuse, or for sale for fuel value, use, or

reuse, and is not considered a control device. This definition

of recovery device is imbedded within the definition of control

device.

2.13.2 Compliance Determination

Comment: Commenter IV-D-06 recommended that the EPA provide

an exemption from performance testing for RCRA-regulated

hazardous waste incinerators. According to the commenter,
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RCRA-regulated hazardous waste incinerators have already had to

demonstrate compliance with very stringent emission standards

under RCRA, and no further compliance demonstration is needed for

MACT standards. The commenter requested that the EPA use the

wording in §63.116(b)(5) of subpart G of the HON, verbatim, in

§63.1281(d)(3)(i) as a new paragraph (d)(3)(i)(E). The commenter

stated that this comment also applies to subpart HH.

Response: The EPA is not aware of any oil and natural gas

exploration and production or natural gas transmission and

storage facilities that would have RCRA industrial furnaces. 

However, the EPA has added the recommended language based on

§63.116(b)(5) of subpart G of the HON to final subparts HH and

HHH [codified at §63.772(e)(1)(v) of final subpart HH and

§63.1282(d)(3)(v) of final subpart HHH].

Comment: Commenter IV-D-06 suggested that the EPA include

an exemption from performance testing under subpart HHH, for

control devices that have already had a performance test under

other EPA regulations. The commenter stated that the EPA should

use the language in §63.116(b)(3) of the HON, verbatim, and used

in subpart HHH as a new paragraph (d)(3)(i)(F). The commenter

stated that this comment also applies to subpart HH. [Note: The

commenter did not provide section number in subpart HHH, it can

be assumed that they were referring to §63.1281.]

Response: The EPA agrees that control devices that have had

a performance test under other EPA regulations should be exempt

from the performance test requirements under subparts HH and HHH. 

Therefore, the EPA has added a new paragraph (vi) to

§63.772(e)(1) of final subpart HH and §63.1282(d)(1) of final

subpart HHH as follows:

(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.
2-188

Comment: Commenter IV-D-06 suggested that subpart HHH

specify what constitutes a compliance demonstration for flares. 

According to the commenter, subpart HHH never says whether a

compliance demonstration is required for flares, or how to

conduct a compliance demonstration. The commenter cited three

examples where §63.1281(d)(3)(ii) points to §63.11(b) of subpart

A, and does not contain a specific requirement for a compliance

demonstration:

C Section 63.11(b) requires the fuel for a flare to have a

certain minimum net heating value and how the net heating

value would be determined. However, nothing in §63.11(b)

says the owner or operator must actually perform the

calculations at a certain time, on a certain fuel, to

demonstrate compliance.

C Section 63.11(b) requires that flares be designed for, and

operated with, no visible emissions and what test method

must be used to determine whether there are visible

emissions. However, nothing in §63.11(b) says the owner or

operator must actually perform the visible emissions test at

a certain time, to demonstrate compliance.

C Section 63.11(b) requires that steam-assisted and

nonassisted flares be designed for and operated with an exit

velocity less than a certain figure, with specified

exceptions. Air-assisted flares are given a different limit

for the exit velocity. The regulations also provide a

method for determining the exit velocity in each case. 

However, nothing in §63.11(b) says the owner or operator

must determine the exit velocity at a certain time, to

demonstrate compliance.

The commenter contended that if subpart HHH references §63.11(b)

for flares, nothing requires a compliance demonstration for

flares. The commenter stated that they believe that enforcement

actions have been taken by some EPA personnel, based on the

interpretation that §63.11(b) requires a compliance demonstration

for flares. However, the commenter does not think that §63.11(b)

actually requires a compliance demonstration. Therefore, the

commenter requested that subpart HHH specify what elements are

included in the compliance demonstration and what the deadline

is. The commenter provided the following language that could be

inserted to replace §63.1281(d)(3)(ii).
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(ii) Notwithstanding any other provision of this

subpart, if an owner or operator uses a flare to comply

with any of the requirements of this subpart, the owner

or operator shall comply with (ii)(A) through (ii)(C)

of this paragraph. The owner or operator is not

required to conduct a performance test to determine the

percent emission reduction or outlet HAP or TOC

concentration. If a compliance demonstration has been

conducted previously for a flare, using the techniques

specified in (ii)(A) through (ii)(C) of this paragraph,

that compliance demonstration may be used to satisfy

the requirements of this paragraph if either no

deliberate process changes have been made since the

compliance demonstration, or the owner or operator can

demonstrate that the results of the compliance

demonstration reliably demonstrate compliance.

(A) Conduct a visible emissions test using the

techniques specified in §63.11(b)(4) of subpart A;

(B) Determine the net heating value of the gas

being combusted, using the techniques specified in

§63.11(b)(6) of subpart A; and

(C) Determine the exit velocity using the

techniques specified in either §63.11(b)(7)(i) and

§63.11(b)(7)(iii) where applicable, or §63.11(b)(8), as

appropriate.

The commenter stated that this comment also applies to subpart

HH.

Response: The EPA agrees that specific requirements for a

flare compliance test are necessary. Therefore, the final rules

contains §63.772(e)(2) (for subpart HH) and §63.1282(d)(2) (for

subpart HHH) as follows:

(2) An owner or operator shall design and operate

demonstrate the performance of each flare in accordance

with the requirements specified in §63.11(b) and in

paragraphs (e)(2)(i) and (ii) [or (d)(2)(i) and (ii)

for subpart HHH] 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. 

Comment: Regarding the requirement for combustion sources

(95-percent emission reduction, or 20-ppmv outlet concentration),

commenter IV-D-07 asked how compliance with the requirement is to
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be demonstrated, and under what operating conditions the

requirement is applicable.

Response: Compliance with the requirement for combustion

sources (95-percent emission reduction, or 20-ppmv outlet

concentration) is demonstrated by monitoring specified operating

parameters [see §63.773(d)(3)(i)(A) through (G) of final

subpart HH or §63.1283(d)(3)(i)(A) through (G) of final subpart

HHH for specific parameters]. For each operating parameter

monitored, the owner or operator selects a minimum or maximum

operating parameter value (as appropriate) at which the control

device must be operated continuously to achieve the applicable

performance requirements. The minimum or maximum operating

parameters are established based on the control device

manufacturer's recommendation along with either values measured

during a performance test or the control device design analysis. 

For example, §63.773(d)(3)(i)(A) of final subpart HH requires an

incinerator to be equipped with a temperature monitoring device. 

The owner or operator must establish a minimum operating

temperature, either by performance test, or design analysis, at

which the incinerator must be operated continuously to achieve

95-percent emission reduction. The data collected by the

temperature monitoring device must not fall below the minimum

operating temperature.

Emissions from a glycol dehydration unit are required to be

routed to a control device if the glycol dehydration unit has a

natural gas throughput greater than 3 MMscf/d or benzene

emissions greater than 1 tpy. If the owner or operator chooses

to use a combustion device to comply with the process vent

control requirements, the combustion device must achieve

95-percent emission reduction or 20-ppmv outlet concentration. 

In addition, the final rule allows owners or operators to install

control technologies that reduce emissions from glycol

dehydration unit process vents to 1 tpy of benzene or less.

Comment: Commenter IV-D-14 asked how operating parameter

values used in demonstrating compliance would be assigned and who

would be responsible for determining the appropriate values.
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Response: The owner or operator is responsible for

determining the appropriate operating parameter values (either as

a minimum or a maximum) to use to demonstrate compliance

[§63.773(d)(5) of final subpart HH and §63.1283(d)(5) of final

subpart HHH]. The operating parameter values must be based on

either performance testing or design analysis, supplemented with

the manufacturer's recommendations [§63.773(d)(5)(i)(A) and (B)

of final subpart HH and §63.1283(d)(5)(i)(A) and (B) of final

subpart HHH]. The established operating parameters and the 

rationale for choosing them, must then be submitted in the

Notification of Compliance Status Report [§§63.775(d)(5) and

63.1285(d)(5) of the final rules].

Comment: Commenter IV-D-12 requested that the EPA clarify

the methods proposed for demonstrating adequacy of control

performance and that the EPA provide examples to show how these

methods should be applied.

Response: The EPA agrees that subparts HH and HHH should be

clarified to specify when performance tests or design analyses

should be conducted. Therefore, the EPA has language to subparts

HH and HHH to clarify how compliance is demonstrated using

performance tests and design analyses. Section 63.772(f) of

final subpart HH and §63.1282(e) of final subpart HHH contain

requirements for demonstrating compliance for all control

devices. As an alternative, the owner or operator may choose to

demonstrate compliance using condensers in accordance with

§63.772(g) of final subpart HH or §63.1282(f) of final

subpart HHH.

Sections 63.772(e)(4) and 63.1282(d)(4) of the final rules

specify that the performance tests must be conducted according to

the schedule in §63.7(a)(2) of subpart A and the results must be

submitted in the Notification of Compliance Status Report

required in the appropriate subpart. Examples of how test

methods should be applied will be included in implementation

guidance to be published after the promulgation dates for

subparts HH and HHH.
2-192

Comment: Commenter IV-D-12 stated that a design analysis is

the appropriate way to demonstrate control device efficiency

because methods to perform emissions performance tests on

dehydrator vent streams are unreliable. However, the commenter

stated that approval of the design analysis on a case-by-case

basis is inappropriate and could result in "an administrative

bottleneck to efficient implementation of the standard." The

commenter recommended that the EPA define calculations and

records to demonstrate control efficiency and that records be

kept on file similar to that required by some NSPS.

Response: The EPA provided the option for an owner or

operator to perform design analyses instead of a performance test

because design analyses are a generally less expensive option,

and simpler to perform than conducting a performance test. 

However, due to the potential for variability in design analyses,

the EPA believes that approval on a case-by-case basis is

necessary. Therefore, the EPA has not modified subparts HH and

HHH in response to this comment.

Comment: Commenter IV-D-05 referred to §63.772(f) which 

allows for an alternative to the documented test procedures of

§63.772(e) if the ARL test is performed in accordance with the

procedures in GRI-95/0368.1. According to the commenter, this

type of test will not give results of how a condensing unit is

working because glycol concentrations are not changed just

because a condensing unit is added to the still column vent. The

commenter recommended that the EPA allow the use of GLYCalc as an

alternative since it was designed to model the emission effects

of various control devices. In support of this recommendation,

the commenter noted that using GLYCalc is allowed to determine

exemptions from the control requirements.

Commenter IV-D-22 recommended that the EPA amend Section

63.772(b)(2) by adding subpart (iii) as follows:

(iii) The owner or operator shall determine an

average emissions rate of benzene in tons per year

following the procedures specified in GRI Publication

95/0368, March 1996.
2-193

The commenter stated that the ARL method has been approved as an

accurate method of measuring emissions by the EPA Emission Factor

and Inventory Group (memorandum, dated October 26, 1995). The

commenter also recommended that the EPA amend §63.772(f) to make

it clear that the ARL method can be used to calculate BTEX

emissions from a dehydrator in an uncontrolled state. To

calculate condenser control efficiency, as intended in

§63.772(f), the results of the ARL method must be used in

conjunction with GLYCalc to calculate condenser control

efficiency. The commenter recommended that the EPA amend

§63.772(f) by inserting "in conjunction with GLYCalc to calculate

control device performance" at the end of the proposed section.

Response: The ARL method is intended to be used for

determining uncontrolled emissions from the glycol dehydrator.

The EPA intended that the ARL method would be used in conjunction

with GLYCalc to determine condenser performance. Therefore,

proposed §§63.772(f) and 63.1282(e) [now codified at

§63.772(e)(5) and 63.1282(d)(5) of the final rules] have been

modified to clarify that the results from the ARL method can be

used as inputs to GLYCalc (Version 3.0) to estimate condenser

control efficiency. 

Additionally, the EPA agrees with the commenter that the ARL

method should be allowed as an input to GLYCalc for estimating

actual benzene emissions. Therefore, §§63.772(b)(2)(i) and

63.1282(a)(2)(i) of the final rules state that the procedures

documented in the GRI report entitled, "Atmospheric Rich/Lean

Method for Determining Glycol Dehydrator Emissions"

(GRI-95/0368.1), can be used in conjunction with GLYCalc to

determine actual benzene emissions.

Comment: Commenter IV-D-07 questioned whether the

parameters listed in §63.1281 for the condenser design analysis

(i.e., vent stream composition, constituent concentrations, flow

rate, relative humidity, and temperature) refer to the natural

gas stream entering the contactor tower. For the outlet, the

commenter also asked if they need to determine the outlet organic
2-194

concentration levels or levels of controlled emissions. The

commenter noted that not all condensers have a specific coolant

fluid for which inlet and outlet temperatures can be measured

(e.g., air-cooled vs. glycol-cooled, water-cooled, or forced

draft).

Response: The parameters required for the condenser design

analysis (i.e., vent stream composition, constituent

concentrations, flow rate, relative humidity, and temperature)

refer to characteristics of the emission stream to be treated by

the condenser, in this case, glycol dehydration unit process vent

streams (consisting of reboiler vent emissions, or flash tank

vent emissions, or both).

The design analysis was intended to provide some relief from

the burden of demonstrating compliance with the control device

performance requirements, by giving the owner or operator an

alternative to performance testing. The parameters required for

the design analysis (i.e., design outlet organic concentration,

design average temperature of the condenser exhaust vent stream,

and the design average temperatures of the coolant fluid at the

condenser inlet and outlet) are required to show that the

condenser was designed, based on the process vent stream

characteristics, to achieve an emission reduction of 95 percent. 

The intent of these design analysis requirements was not to

require monitoring of outlet organic concentration level and

coolant fluid inlet and outlet temperature. However, the design

analysis should show that these factors were considered in the

design analysis when establishing the operating temperature of

the condenser exhaust stream, which is required to be monitored. 

The EPA does not see any reason to modify subparts HH and HHH in

response to this comment.

Comment: Commenters IV-D-08, IV-D-22, and IV-D-30

recommended that the EPA specify GLYCalc as an allowed tool to

perform the design analysis for a condenser to determine

compliance with the control requirements. Commenters IV-D-08 and

IV-D-22 suggested that the design condenser exhaust stream

temperature should be established as the maximum temperature that
2-195

allows the condenser to achieve the control required by

§63.771(d)(1)(ii). Commenter IV-D-22 stated that if GLYCalc is

used to perform the design analysis, the EPA should delete the

references to relative humidity, (air) temperature, and the

design average temperatures of the coolant fluid at the condenser

inlet and outlet, since these parameters are not required by

GLYCalc. Commenter IV-D-30 recommended that the EPA add the

following language to §63.771(d)(3)(iv)(A)(4): "For example,

GLYCalc Version 3.0 or higher is an acceptable design analysis

tool for the purposes of this paragraph."

Response: The EPA agrees that it is appropriate to allow an

owner or operator to use GLYCalc as an alternative to the design

analysis for condensers specified in proposed

§§63.771(d)(3)(iv)(A)(4) and 63.1281(d)(3)(iv)(A)(4) [now

codified at §§63.772(e)(4)(i)(D) and 63.1281(d)(4)(i)(D) of the

final rules] and has modified §§63.772(e)(4)(i)(D) and

63.1282(d)(4)(i)(D) of the final rules accordingly. The

requirements for using relative humidity, temperature, and design

average temperatures of the coolant fluid at the condenser inlet

and outlet in the design analysis are necessary to determine

condenser performance when GLYCalc is not used. Therefore, the

EPA has retained these requirements.

Comment: Commenter IV-G-09 stated that the direct benzene

test in §63.1282(a)(2)(ii) is subject to significant inaccuracy

because of the low pressure differential available for sampling

dehydration unit vents. Therefore, according to the commenter,

the GLYCalc model in §63.1282(a)(2)(i) or some alternative model

is critical to demonstrate compliance successfully.

Response: The EPA agrees with the commenter. As proposed,

subparts HH and HHH provide for the use of GLYCalc as an

alternative for estimating benzene emissions.

Comment: Commenter IV-D-35 referred to proposed

§63.1282(a)(2)(i) which requires the owner or operator to

determine annual benzene emissions using GLYCalc. Inputs to the

model are required to be "representative of actual operating

conditions." The commenter was concerned that the variation in
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the ranges of values and the affect on emissions was uncertain. 

The commenter requested that §63.1282(2)(i) include some guidance

on how the "representative" values for use with GLYCalc are to be

developed. The commenter stated that they have worked with the

industry to develop an approach with no success.

Similarly, the commenter was concerned that proposed

§63.1282(a)(2)(ii) does not address how the glycol dehydration

unit should be set up for a benzene emission test. According to

the commenter, the activity level during a test may not represent

yearly operations. The commenter requested guidance to produce

meaningful results and stated that the use of the GLYCalc model

may become very limited without guidance on input parameters in

the proposed regulation.

Response: Because of the great variability in the operation

of glycol dehydration units in the oil and natural gas production

and natural gas transmission and storage source categories, the

EPA could not develop guidance on what may be considered

representative parameters within the final rules. However, the

EPA plans to publish implementation guidance for these rules,

following promulgation. It is up to the owner/operator to select

and document the appropriate values for the parameters that they

will be using as representative values.

Comment: Commenter IV-G-14 requested that GLYCalc not be

used to determine BTEX emissions from reboilers. The commenter

was concerned that conditions may be altered to slant emissions

to the low side. The commenter also stated that some companies

are taking gas samples downstream of glycol contact towers,

resulting in unrepresentative temperatures of the gas being

processed being reported. The commenter stated that the GLYCalc

program is not as acceptable as actual testing because of

potential inaccuracies. However, the commenter stated that if

typical conditions were listed as a guide for the reviewer to go

by, then GLYCalc would be an acceptable method for determining

emissions. The commenter noted that if the sampling port is

downstream of a glycol contact tower the measurement would not be

accurate because of glycol's affinity for benzene. The commenter
25 Reference 24.

26 Radian International LLC. Technical Reference Manual for

GRI-GLYCalcTM: A Program for Estimating Emissions from Glycol

Dehydration of Natural Gas, Version 3.0. Prepared for Gas

Research Institute. Chicago, Illinois. GRI-96/0091. March 1996.

pp. 7-1 through 7-14.

27 Reference 26.

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also stated that safety concerns and moisture concerns are not

problems for good stack testers.

Response: As stated in a previous response, the EPA

reviewed GLYCalc and has determined that the program is an

acceptable method for estimating emissions from glycol

dehydration units.25 The EPA also believes that owners/operators

who use this program will determine accurate emission estimates

due to the documentation required to establish representative

parameters. The EPA intends to publish implementation guidance

after the promulgation of subparts HH and HHH to aid inspectors

in the evaluation of compliance with the regulations.

Sections 63.772(b)(2)(i) and 63.1282(a)(2)(i) of the final

rules allow an owner or operator to use the ARL method as an

input to GLYCalc. The ARL method specifies where the gas samples

must be collected. When not using the ARL method, the GLYCalc

manual26 provides guidance for the best locations for collecting

gas samples. Therefore, §§63.772(b)(2)(i) and 63.1282(a)(2)(i)

of the final rules specify that the owner or operator should use

the procedures specified in the GLYCalc Manual for collecting gas

samples.27

Comment: Commenter IV-G-15 recommended that the Agency

require stack testing of controlled and uncontrolled emissions

points whenever possible, especially where condensers are used. 

The commenter submitted examples of testing methods (including

proposed sampling procedures for testing glycol dehydrators

submitted at the commenter's request by commenters IV-G-16 and

IV-G-17), and requested that the test methods in the final rule

specify how to test instead of providing general guidance on
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testing. The commenter noted that LDEQ has conducted emissions

tests of compressors and boilers in addition to other emissions

points in the source category. The commenter noted that benzene

emissions are significant and should be tested rather then

modeled. 

Response: The EPA provides an owner or operator with the

option of conducting an emission source test (i.e., a stack test)

or design analysis. The EPA realizes that an emission source

test may impose a severe burden on many owners or operators (the

costs associated with planning and conducting such a test) in the

oil and natural gas production and natural gas transmission and

storage source categories. Thus, the EPA included design

analyses as an acceptable option for demonstrating compliance to

reduce the overall burden. The EPA includes references to

appropriate emission measurement methods and does not believe

that articulating how to test is necessary. Therefore, the EPA

has not modified subparts HH and HHH in response to this comment.

Comment: Commenters IV-D-22 and IV-G-11 requested that the

EPA clarify compliance obligations by expressly indicating in

§63.760(e) that the facilities failing to meet storage vessel

thresholds of §63.764(c)(2) or that meet the glycol unit

exemptions of §63.764(e) are not subject to any requirements of

subpart HH.

Response: The EPA has determined that for the class of

storage vessels that do not have the potential for flash

emissions, the MACT floor is no control. Therefore, storage

vessels with the potential for flash emissions are defined in

final subpart HH to mean any storage vessel that contains a

hydrocarbon liquid with a stock tank GOR greater than or equal to

1,750 scf/barrel and an API gravity greater than or equal to 40

degrees, and a hydrocarbon liquid throughput greater than or

equal to 500 bpd. Since the affected source at an oil and

natural gas production facility is defined, in §63.760(b) of the

final rule, as each storage vessel with the potential for flash

emissions, owners or operators of storage vessels that do not

meet the definition of storage vessels with the potential for
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flash emissions, have no further obligations for those storage

vessels under subpart HH. However, it should be noted that the

owner or operator is subject to §63.10(b)(3) of subpart A and

must maintain records of applicability determinations.

Each glycol dehydration unit with an actual annual average

natural gas throughput less than 3 MMscf/d or with actual average

benzene emissions less than 1 tpy are not exempt from the

subpart, but are subject to recordkeeping and reporting

requirements. In addition, these units must be included in the

calculation of PTE for major source applicability determinations. 

Furthermore, the exemptions provided in §63.764(e) do not apply

to entire facilities, but to each individual glycol dehydration

unit. Therefore, providing a general exemption for a facility in

§63.760(e) would not be applicable. 

As proposed, ancillary equipment and compressors located at

natural gas processing plants with a VHAP concentration less than

10 percent and in VHAP service for less than 300 hours per year

were not subject to the recordkeeping and reporting requirements. 

However, the EPA believes that recordkeeping requirements for

these equipment are appropriate. Therefore, §63.755(d)(2) of

final subpart HH contains recordkeeping requirements for the

documentation of the information and data used to determine which

ancillary equipment and compressors are exempt from the control

requirements of §63.769 of subpart HH.

2.13.3 Compliance Dates

Comment: Commenter IV-D-38 suggested that §63.760(f)(2) be

modified so that the effective date for new construction and

reconstruction be six (6) months after the final rules are

promulgated. The commenter was concerned that if the final rule

is much less stringent than the proposed rule, operators would

unnecessarily incur significant expenses to install controls that

comply with the proposed rule.

Response: Sections 63.760(f)(2) and 63.1270(d)(2) of the

final rules specify that the compliance date for new and

reconstructed sources (i.e., sources that commence construction

or reconstruction on or after February 6, 1998) is the date of
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initial startup, or the effective date of the rule, whichever is

later. Therefore, the EPA believes that new or reconstructed

sources have adequate time to comply with the final rule. 

Furthermore, since the final rule is not significantly less

stringent than the proposed rule (i.e., 95 percent control is

required in the final rule), the EPA believes that owners or

operators should not unnecessarily incur significant expenses to

install controls that comply with the proposed rule.
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2.14 WORDING OF REGULATIONS (OTHER THAN APPLICABILITY AND

DEFINITIONS)

Comment: Commenter IV-D-16 recommended that the EPA delete

the phrase "as expeditiously as practical" in proposed

§63.760(f)(1) as it "is open to interpretation and disagreement

by all." As an alternative, the commenter recommended that

compliance should be by three years after the date of final

rulemaking in the Federal Register. The commenter noted that

this had been done by other MACT standards.

Response: The EPA intends for existing sources to achieve

compliance no fewer than three years after the final rule is

published. It is a benefit to the environment for sources to

achieve compliance in less than three years. However, the EPA

understands that the commenter is concerned about enforcement

actions based on the phrase "as expeditiously as practical." The

EPA does not feel that this phrase adds anything to subparts HH

and HHH and has removed it from §§63.760(f)(1) and 63.1270(d)(1)

of the final rules.

Comment: Commenter IV-D-06 requested that the EPA clarify

the difference between "initial startup" and "startup." 

According to the commenter, these two terms do not have the same

meaning. The commenter explained that the time between the

completion of construction and the day of initial startup is used

to try out and debug the equipment. The commenter stated that

these trial runs are not initial startups and should not trigger

the compliance date. The commenter suggested the following

language for §63.1270(d)(2) to clarify and stated that any other

sections in the rule that say "startup" should be changed as

well. 

(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 [the date of publication of the

final rule], whichever date is later.

The commenter stated that this comment may also apply to subpart

HH.
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Response: The EPA agrees that only initial startups should

trigger the compliance dates. Sections 63.760(f)(2) and

63.1270(d)(2) of the final rules have been modified to include

the term "initial startup." Additionally, a definition for

initial startup has also been added to §§63.761 and 63.1271 of

the final rules, as follows:

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.

Comment: Commenter IV-D-06 stated that subpart HHH is a HAP

rule and not a VOC rule. The commenter recommended that

references to VOC in the rule should be corrected. The commenter

presented the following changes to §63.1271, and requested that

any other paragraphs with references to VOC also be changed:

Combustion device means an individual unit of

equipment, such as a flare, incinerator, process

heater, or boiler, used for the combustion of volatile

organic compound HAP vapors.

The commenter stated that this comment may also apply to subpart

HH.

Commenter IV-D-07 questioned whether the EPA was suggesting

a need to look at either TOC or HAP, or both TOC and HAP. 

According to the commenter, before §63.1281, only HAP is referred

to, while §63.1281 refers to a 95-percent reduction of either TOC

or total HAP. 

Response: In response to commenter IV-D-06, and to be

consistent with the definition of combustion device in other

rules, the EPA has made the following change to §§63.761 and

63.1271.

Combustion device means an individual unit of

equipment, such as a flare, incinerator, process

heater, or boiler, used for the combustion of volatile

organic hazardous air pollutant vapors.

The EPA does not intend to regulate VOC or TOC under subparts HH

and HHH, however, TOC has been included as a surrogate for HAP in 

determining control device efficiency. The EPA believes that
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allowing the owner/operator to measure TOC rather than HAP

provides some flexibility for the owners and operators and still

achieves the objective of reducing HAP emissions by the specified

emission reduction.

Comment: Commenter IV-D-06 stated that §63.1281(c) should

say "that closed-vent system must route all HAP gases, vapors and

fumes emitted from the reboiler vent to a control device." The

commenter explained that non-HAP gases and emissions from "the

unit," but not from the reboiler vent (such as fugitive

emissions) should not count.

Response: The EPA agrees that the requirement in

§§63.771(c) and 63.1281(c) should specify that closed-vent

systems should route HAP emissions from an affected source, and

has made the recommended changes to subparts HH and HHH. 

However, the EPA does not agree the commenter's recommendation

that §§63.771(c) and 63.1281(c) should specify that the emissions

from the reboiler vent be routed to the control device through a

closed vent system. In subparts HH and HHH the standards require

closed-vent systems for more emissions points than just the

glycol dehydration unit reboiler vent. Therefore, the EPA has

not made this recommended change. 

Comment: Commenter IV-D-06 pointed out several

typographical errors.

(1) Remove the word "a" from the phrase ". . . either TOC or a

total HAP in the exhaust gases," in §63.1281(d)(1)(i)(B).

(2) In Table 1, "Ethylene glycol" should be "Ethylene glycol"

(3) In Table 1, "p-Xylenea" should be "p-Xylene."

The commenter stated that this comment may also apply to subpart

HH.

Response: The EPA has made the recommended corrections.

Comment: Commenter IV-D-06 requested that the word

"practicable" in §63.1283(c)(4) be changed to the word

"practical." According to the commenter, courts have interpreted

"practicable" to mean "capable of being done," with little regard

to the cost or other difficulties. The commenter was concerned
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that no matter how quickly they fixed a leak, it would have been

"practicable" to fix it sooner. The commenter stated that they

doubted the EPA intended to impose such a severe requirement. 

The commenter also stated that this comment may also apply to

subpart HH. 

Response: The word "practicable" has been used in several

regulations in the past (e.g., subpart H of the HON). The

commenter did not cite, and the EPA is unaware of any instances

where this language has been interpreted incorrectly. Therefore,

the EPA does not see any reason to modify subparts HH and HHH

based on this comment.

Comment: Commenter IV-D-06 requested that the EPA revise

the last sentence of §63.1283(d)(4)(ii) to read ". . . based on

the control device design analysis and/or the control device

manufacturer's recommendations." The commenter stated that this

change would allow the possibility of not following the

manufacturer's recommendations, which is important for the

following reasons:

1. The EPA cannot lawfully delegate rulemaking power to

manufacturers. The commenter felt that the

manufacturers would be given the power to create

binding law (without public notice, or an opportunity

to comment) because whatever they wrote into their

instructions would become mandatory.

2. Sometimes there will not be any single manufacturer to

provide instructions. 

3. Sometimes the manufacturer's instructions will not be

appropriate for the use of the equipment. The

commenter explained that the manufacturer may have

never considered the intended use, or the environment

in which the component would be placed.

The commenter stated that this comment may also apply to subpart

HH. 

Response: The EPA agrees with the commenter. Sections

63.773(d)(5) and 63.1283(d)(5) of the final rules specify that

the minimum or maximum operating parameters should be set based

on: (1) a performance test, supplemented by a control device

design analysis or the control device manufacturer's
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recommendation or a combination of both [§§ 63.773(d)(5)(i)(A)

and 63.1283(d)(5)(i)(A)], or (2) the control device design

analysis, supplemented by the control device manufacturer's

recommendation [§§ 63.773(d)(5)(i)(B) and 63.1283(d)(5)(i)(B)].

Comment: Commenter IV-D-07 stated that no graphic was shown

for Figure 1 (Section III.A.2, page 6294).

Response: The figure is in the Federal Register version of

the regulation (63 FR 6294).

Comment: Commenter IV-D-07 stated that the referenced

equations are missing in the following sections:

63.772(a)(4)(iii)(D), 63.772(a)(4)(iv)(E), 63.1282(d)(3)(ii),

63.1282(d)(3)(iii), 63.1282(d)(4)(ii)(A), and 

63.1282(d)(4)(iii)(B).

Response: The equations are in the Federal Register version

of the regulation (63 FR 6318 and 6331).
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2.15 GENERAL PROVISIONS

Comment: Commenter IV-D-13 stated that additional

rulemaking or preamble language is needed to clarify the

applicability of the General Provisions (40 CFR part 63,

subpart A) to subpart HH. Commenter IV-D-06 stated that

subpart HHH should not defer to subpart A, because according to

the commenter, the General Provisions have significant flaws and

should not be used as the basis for compliance in the MACT

standard. The commenter provided four examples of flaws in the

General Provisions.

1. Section 63.6(e)(3)(i)(A) says that the startup,

shutdown, and malfunction plan must ensure that sources

are operated in a manner that will minimize emissions

"at least to the levels required by all relevant

standards." The commenter remarked that this provision

could be interpreted two ways, and neither one will

work. According to the commenter, one interpretation

could mean that emissions have to be minimized "as much

as the relevant standards require during startup,

shutdown, and malfunctions." The commenter stated that

this will not work because the relevant standards refer

to §63.6 for the requirements, resulting in an endless

loop, with neither standard stating the requirements. 

The second interpretation could mean that emissions

have to be minimized "as much as the relevant standards

require during normal operation when there is not any

startup, shutdown, or malfunction." The commenter

noted that this is impossible, and would eliminate the

reason for having special provisions for startups,

shutdowns, and malfunctions.

2. The general provisions do not specifically address

shutdowns of compliance equipment such as control

devices. According to the commenter, under a literal

reading of a MACT standard, the owner or operator might

simply elect to shut down all the control devices and

assert that no further emission standards apply because

this is a "shutdown."

3. The General Provisions do not specifically address that

some startups, shutdowns, and malfunctions affect only

a portion of the process. According to the commenter,

an owner or operator might assert that a malfunction in

one small, localized portion of a process justifies

shutting down the controls throughout the entire

process, even though the malfunction does not impair

the ability of other portions of the process to comply

with the emission standards.
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4. The General Provisions do not say how to deal with

periods of non-operation when the relevant emissions

have ceased. According to the commenter, a shutdown is

a transitional state between operation and

non-operation. The commenter stated that once the

shutdown is complete, the process is idle and is not

producing emissions. The commenter contended that it

doesn't make sense to impose control requirements when

there are no emissions. The commenter further

explained that some inspectors have interpreted

standards such that control devices must be monitored

even when there is nothing for them to control. The

commenter stated that the HON and other rules clarify

that when there is nothing to monitor (i.e., when the

process is not operating and there are no emissions),

parameter monitoring of control devices is not required

and sometimes a failure to monitor may be excused

during startups, shutdowns, and malfunctions. The

commenter explained that there are instances where

imposing a requirement to continue monitoring would be

inappropriate. For example, monitoring cannot be

continued if the monitoring device has a malfunction or

it might be necessary to "valve off" the monitoring

device to keep the device from being damaged. 

Because of the problems with the General Provisions, the

commenter recommended that the EPA should not use the General

Provisions as a basis for handling startups, shutdowns, and

malfunctions. The commenter suggested that the EPA put

provisions equivalent to the HON into §63.1272, which is

currently reserved. The commenter provided the following

language for the new §63.1272:

(a) The provisions set forth and 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, if a

startup, shutdown, malfunction, or period of

non-operation of one portion of an affected source does

not affect the ability of a particular emission point

to comply with the specific provisions to which it is

subject, then that emission point shall still be

required to comply with the applicable provisions of

this subpart 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
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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 portion thereof.

(c) During startups, shutdowns, and malfunctions

when the requirements of this subpart do no 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 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.

The commenter also suggested adding the words "Except as

otherwise provided in this subpart" to start §63.1281(d)(2). The

commenter stated that this comment may also apply to subpart HH. 

Additionally, the commenter requested that the EPA modify Table 2

to list paragraph-by-paragraph the applicability of §63.6(e) to

subpart HHH. The commenter stated that this comment also applies

to subpart HH.

Response: The EPA disagrees with the commenters that there

are significant "flaws" in the existing subpart A General

Provisions. However, the General Provisions are designed to be

general in nature, and individual NESHAP may have reasons to

override them to implement the intent of the General Provisions

in a standard-specific setting. Consequently, the EPA has

considered the commenters' concerns related to the startup,

shutdown, and malfunction (SSM) provisions in §63.6(e) and has

added the language suggested by commenter IV-D-06 to §§63.762 and

63.1272 of the final rules. In addition, §§63.762 and 63.1272 of

the final rule specify that an owner or operator must prepare a
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startup, shutdown, or malfunction plan as required in

§63.6(e)(3), except that the plan is not required to be

incorporated by reference into the title V permit.

The commenter is concerned that the requirement for the SSM

plan to ensure that sources are operated in a way that will

minimize emissions "at least to the levels required by all

relevant standards" may result in unclear requirements or will be

impossibly stringent by requiring sources to meet the NESHAP

requirements during all SSM events. The intent of the

requirements in §63.6(e) is that sources do their best to

minimize emissions to the levels of the required standards (i.e.,

the individual subpart). This does not mean, however, that the

source would be required to operate better than the standards or

even to meet the standards during the SSM period, if the source

is in compliance with the SSM plan. Because no plan can cover

every conceivable situation, the duty of the owner or operator is

to do the best he or she can to minimize emissions during all

events, even those not specifically addressed by the plan, based

on good engineering judgement, expertise, and familiarity with

the equipment, as well as following protocols for similar events

that are in the SSM plan, if any.

Commenter IV-D-06 suggested that the General Provisions

could be interpreted to allow a source to shut down control

devices to "eliminate" emissions or to shut down controls for an

entire process if only a portion of that process has a SSM event. 

Section 63.2 of the General Provisions defines shutdown as the

"cessation of operation of an affected source for any purpose." 

The EPA believes that the general duty to operate and maintain at

all times, including periods of SSM, "any affected source,

including associated air pollution control equipment, in a manner

consistent with good air pollution control practices for

minimizing emissions" [§63.6(e)(1)(i)] precludes the possibility

of sources invoking the commenter's interpretation. In fact,

such actions would be considered a violation of the requirements.

The EPA agrees that there are limited cases where continued

monitoring of air pollution control devices during periods of SSM
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serves no useful function. These cases should be addressed in

the source's SSM plan, which the State has the authority to

review and approve. However, to address the commenter's concern,

§§63.773(d)(8) and 63.1283(d)(8) of the final rule specify that

emissions during SSM events when the facility is operated in

accordance with the SSM plan, and periods of non-operation of the

unit or process that is vented to the control device (which

result in cessation of emissions), are not considered excursions.

Although the HON requirements do not specifically require

monitoring during periods of SSM, EPA policy is that,

unpromulgated rules should incorporate requirements for

monitoring to be continued at all times. This includes

monitoring during periods of SSM, since these records will

provide the Agency valuable information on the adequacy of the

source's SSM plan and also adherence to the requirement that

emissions are minimized.

Comment: Commenter IV-D-06 requested that the EPA revise

Table 2 to say that §63.7(c) does not apply to subpart HHH. 

According to the commenter, the requirement in §63.7(c) of the

General Provisions for a site-specific test plan is "unduly

burdensome" and has not been required in various other MACT

standards. The commenter stated that if subpart HH also

incorporates §63.7(c), then this comment also applies to subpart

HH.

Response: Site-specific test plans must be developed, but

only need to be submitted to the Administrator for approval upon

request of the Administrator. Subparts HH and HHH do not

specifically require a site specific test plan. Therefore, to

provide State and local permitting authorities the authority to

request site-specific test plans, the EPA has not changed the

applicability of §63.7(c) to subparts HH and HHH.

Comment: Commenter IV-D-16 stated that the requirements of

§63.6(e)(3) to prepare and follow a startup, shutdown, and

malfunction plan should not be applicable to sites in subpart HH,

since they are likely to be unmanned. The commenter did suggest

that manned gas plants could be required to develop a plan, but
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other sources subject to subpart HH should not be subject to

§63.6(e)(3).

Response: The EPA disagrees that unmanned sites should not

have SSM plans. Such plans are perhaps even more essential at

unmanned sites to ensure that emissions are minimized and

problems addressed as soon as possible. Plans at these sites may

include alarm systems and computerized protocols and other

measures to ensure that appropriate steps are taken to notify

operators of problems and to initiate steps to minimize

emissions. Automated process shutdowns may be required when

certain events occur.
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2.16 MISCELLANEOUS

2.16.1 Health Effects

Comment: Commenter IV-D-28 stated that the EPA should

qualify its statement regarding ethyl benzene's potential

inhalation effects, and reference the many assumptions and

uncertainty factors required in extrapolating from experimental

results in animal studies to potential human effects at actual

concentrations found in the environment.

Response: The proposed rule is technology-based rather than

risk-based, so the summary of toxic effects for ethyl benzene has

no influence on the proposed NESHAP. The EPA included health

effects summaries for ethyl benzene and the other hazardous air

pollutants emitted by this source category to provide the public

with background information about possible effects of

overexposure. The EPA agrees that there are substantial

uncertainties associated with interspecies extrapolation, and has

established national risk assessment guidelines to incorporate

these uncertainties into risk assessments. However, no risk

assessment has been performed in support of the proposed rule. 

Thus, the requested explanation of how these uncertainties are

considered, which would necessarily be detailed and long, would

serve no useful purpose.

Comment: Commenter IV-D-28 stated that while the EPA does

not identify the studies on which the conclusions on ethyl

benzene inhalation effects are based, it appears to be relying

principally on adverse effects observed in animal studies.

Response: Given the brevity of the summary, the EPA

believes it has clearly and fairly represented where animal and

human studies have been considered. The use of animal data in

this context is not unusual. Lack of adequate human data for

long-term exposures often makes it necessary to rely on animal

data to predict potential health effects.

Comment: Commenter IV-D-28 stated that the EPA has

frequently used qualifying language in describing the health

effects associated with chemicals . . . for purposes of other
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NESHAP. The commenter suggested that the EPA should include

similar [qualifying] language in this preamble. 

Response: The EPA agrees that the suggested qualifying

text, excerpted from the NESHAP for the printing and publishing

industry, accurately reflects the EPA's current thinking on

hazard identification, as expressed in the Agency's guidance on

risk assessment. However, although the EPA believes that the

lack of such qualifying text in this proposal does not

necessarily mislead the public about the purpose of the proposed

rule, this language has been included in the preamble to the

final rule.

Comment: Commenter IV-D-28 stated that the EPA also should

state that its summary is not intended to be relied on to

characterize ethyl benzene's potential inhalation toxicity.

Response: The EPA has not suggested anywhere in the

proposed rule that this brief paragraph should serve as a risk

characterization. The section presents only a qualitative

description of effects that may result from overexposure, and

does not suggest where, when, or if such overexposure may occur.

Comment: Commenter IV-D-28 stated that the preamble fails

to include any review of the scientific database on ethyl

benzene's toxicological effects, or reference any animal or human

inhalation studies of ethyl benzene. According to the commenter,

absent such a review the EPA should not publish, in a Federal

Register notice, findings regarding a chemical's health risks.

Response: The EPA agrees with the commenters' point that

risk assessment findings should be fully supported by a review of

the toxicological database. However, the 5-sentence summary of

toxic effects cannot be construed as a risk assessment for ethyl

benzene. It contains only qualitative descriptions of potential

effects of overexposure, and presents no findings regarding risks

from ethyl benzene exposure (or any information at all about

exposure). This paragraph does not need to be, and makes no

pretense of being, a fully-referenced review of the scientific

database.
28 Agency for Toxic Substance and Disease Registry , 1997. 

Toxicological Profile for Ethyl benzene. Public Comment Draft. 

Toxicology Information Branch, Atlanta, GA

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Comment: Commenter IV-D-28 stated that the EPA states that

"short-term inhalation of high levels of ethyl benzene in humans

may cause throat and eye irritation, chest constriction, and

dizziness." The commenter requested that the EPA delete this

statement from the preamble to the final rule. The commenter

further stated that if the EPA does not delete the discussion

entirely, the EPA should, at a minimum, acknowledge the

substantial database demonstrating the absence of acute effects

following inhalation exposure to ethyl benzene.

Response: The EPA based its description of short-term

respiratory and ocular effects on a review of the toxicological

literature by the U.S. Agency for Toxic Substance and Disease

Registry (ATSDR).28 ATSDR's supported its description of throat

irritation, chest constriction, and burning eyes accompanied by

profuse lacrimation at ethyl benzene levels above 1000 parts per

million with numerous literature citations. The commenters'

citation of other studies that failed to show such effects, while

potentially interesting, does not change the results of studies

that did report these effects.

Comment: Commenter IV-D-28 stated that the EPA also should

acknowledge that levels of ethyl benzene in the ambient air are

well below those at which adverse health effects have been

observed.

Response: The EPA's preamble to the proposed rule

(paragraph 1, last sentence) states, "In general, these findings

have only been shown with concentrations higher than those in the

ambient air." This statement applies to ethyl benzene as well as

the other hazardous air pollutants for which the preamble

describes health effects. The EPA believes that this statement

already addresses the commenter's concerns in a manner that is

more than fair. Because the EPA lacks positive evidence that all

locations in the United States are free from hazardous ambient
29 Reference 28.

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concentrations of ethyl benzene, it is impossible to further

strengthen this statement.

Comment: Commenter IV-D-28 requested that the EPA delete,

or qualify substantially, its statement regarding ethyl benzene's

teratogenic effects in animals to reflect the toxicological

database accurately.

Response: ATSDR's 1997 review of the health effects of

ethyl benzene,29 describes several animal inhalation studies that

reported delayed skeletal development, increased incidence of

extra ribs, and renal malformation. The EPA believes that the

sentence currently in the preamble, "Birth defects have been

reported in animals exposed via inhalation; whether these effects

may occur in humans in not known," is a fair condensation of

ATSDR's review. As with the acute effects above, the commenter's

citation of a study for which no teratogenic effects were found

does not change the conclusion, based on positive data, that such

effects are possible.

Comment: Commenter IV-D-28 requested that the EPA delete,

or revise substantially, its discussion of ethyl benzene's

potential chronic health effects. According to the commenter, the

EPA's statement does not accurately describe ethyl benzene's

potential hematological effects and may potentially mislead

users, consumers, and regulatory bodies about the health risks

associated with repeated exposure to ethyl benzene. 

Additionally, the EPA's statement is inconsistent with the

relatively low toxicity assigned to ethyl benzene under the EPA's

Sector Facility Indexing Program (SFIP).

Response: The EPA agrees that the language in the current

preamble does not describe ethyl benzene's chronic effects well,

or in fact at all. Reported effects to the rodent kidney include

increased kidney weight and increased activity of several kidney

enzymes. Hepatic effects reported in animal studies include

increased liver weight, altered enzyme activity, and degenerative
2-216

changes in liver cells. Hematologic effect reported in workers

occupationally exposed to ethyl benzene include decreased

hemoglobin levels and increased lymphocyte count. The EPA

believes the current brief description, "Animal studies have

reported blood, liver, and kidney effects associated with ethyl

benzene inhalation." is consistent with these findings and does

not think additional background detail is needed to support the

proposed rule.

The EPA also agrees that ethyl benzene has relatively low

toxic potential when compared with many other substances listed

as hazardous air pollutants under section 112 of the Clean Air

Act. However, the proposed action is not based on a risk

assessment, and the preamble language therefore does not intend,

or need, to convey information about risk. The one-sentence

listing of chronic health effects refers only to adverse effects

that may occur if the dose of ethyl benzene is high enough. Any

further discussion of relatively low toxicity would need to be

accompanied by information about the large amounts of ethyl

benzene emitted relative to other, more toxic, pollutants, none

of which would be germane to the proposed rule.

Comment: Commenter IV-D-28 requested that the EPA clarify

that adverse health effects have been observed only at ethyl

benzene levels substantially higher than those found in the

ambient air.

Response: The commenters' data on ethyl benzene

concentrations is generally consistent with the EPA's data. The

EPA agrees that our current understanding, based on these air

monitoring data and on modeled concentrations, suggests that

ethyl benzene does not currently pose a national threat. 

However, measured concentration data are sparse, and detailed

modeling has not been conducted for many areas. These very

substantial data gaps prevent the EPA from conclusively stating

that no location in the United States experiences ethyl benzene

levels above the reference concentration.

Furthermore, the National Toxicology Program (NTP) recently

released data that suggest ethyl benzene may be carcinogenic in
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animals. If further studies bear this out, perceived "safe"

levels of ethyl benzene may change substantially. This

uncertainty about carcinogenicity also prevents any categorical

guarantee of safety from health effects of ethyl benzene. The

EPA believes the current statement, "In general, these findings

have only been shown with concentrations higher than those in the

ambient air," is the strongest that can accurately be made.

2.16.2 Other Miscellaneous Comments

Comment: Commenter IV-D-06 supported semiannual reporting

of actions inconsistent with the startup, shutdown, and

malfunction plan instead of immediate reporting and suggested

that the EPA apply the concept to all MACT standards (including

standards that have already been promulgated). The commenter

cited three reasons that immediate reporting has been an

unnecessary burden. First, the commenter contended that just

because actions are inconsistent with the startup, shutdown and

malfunction plan, does not mean that excess emissions have

occurred. Second, even if excess emissions have occurred, they

are not necessarily an immediate health threat (most HAP concerns

are related to long-term, rather than short-term, exposure). 

Third, in any case where short-term emissions may be a concern,

there are better ways to address those concerns (including

immediate reporting under CERCLA section 103 or SARA section 304,

or emergency response actions under EPA's Risk Management

Programs rule implementing section 112(r) of the Act). The

commenter stated that retrofitting semiannual reporting into

existing MACT standards should not be a major burden on the EPA

as it is a minor change and would not likely be controversial.

Response: While the EPA is continually reviewing the

burdens imposed by its regulations in an attempt to reduce these

burdens, no changes have been identified at this time.

Comment: Commenter IV-D-38 stated that the proposed rules

exceed the EPA's authority under section 112 of the CAAA and the

intent of Congress in promulgating the CAA.
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Response: The EPA is required to develop NESHAP under

section 112(d) of the CAA for listed source categories and has

not exceeded its authority.

Comment: Commenter IV-D-04 stated that based on the data

presented by the EPA, there are many small natural gas

production, transmission and storage facilities that are small

sources of HAP. According to the commenter, these sources are

already regulated under State rules and the commenter requested

that the EPA not regulate these sources further.

Response: When developing the MACT floor for production and

transmission and storage facilities, the EPA made several

distinctions between sizes of emissions units. For example, the

EPA developed a MACT floor for large glycol dehydration units

(natural gas flowrate greater than or equal to 3 MMscf/d or

benzene emissions greater than or equal to 1 tpy) and one for

small glycol dehydration units (natural gas flowrate less than 3

MMscf/d or benzene emission less than 1 tpy). In this case, the

MACT floor for small glycol dehydration units was determined to

be no control and these units are not required, in the final

rules, to be controlled. Therefore, the NESHAP are focussed on

facilities with significant HAP emissions. These criteria will

exempt a large number of facilities in the oil and natural gas

production and natural gas transmission and storage source

categories from regulatory requirements and installation of

controls due to their small size and low emissions. These

applicability criteria include benzene emission rate, natural gas

throughput, storage tank throughput, and hours of operation and

apply only to major sources.
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2.17 GENERAL COMMENTS SPECIFIC TO SUBPART HHH (NOT OTHERWISE

ADDRESSED)

Comment: Several commenters were concerned with the EPA's

proposed standard for the natural gas transmission and storage

source category and the EPA's apparent lack of information used

to develop the standard. Commenter IV-D-31 stated that the

inclusion of natural gas transmission and storage in the oil and

natural gas production rulemaking has compromised the regulatory

process and denied affected stakeholders equal opportunity for

input. Although the commenter was pleased that the EPA created a

separate source category for the transmission and storage

industry, they suggested that the EPA did not truly develop

separate MACT standards for the two source categories. 

Furthermore, the commenter stated that including the transmission

and storage source category in this proposal is inconsistent with

the procedures of the CAA of 1990. According to the commenter,

the EPA extended the oil and natural gas production source

category, without adequate notice and opportunity to comment to

include the natural gas transmission and storage sources.

The commenter stated that the EPA is obligated to provide

equal opportunity for the natural gas transmission and storage

industry to work with the EPA during the rulemaking process. The

commenter further stated that regulating both sources

simultaneously, to save limited resources, does not justify

"abandoning well-established procedures for developing a MACT

that is achievable." The commenter stressed that in raising

these issues they are not attempting to avoid or delay regulation

but insisting on the right to the benefit of the full MACT

development process, including source category listing, data

gathering, determination of a MACT floor, and source

category-specific standards.

Commenters IV-D-07, IV-D-12, IV-D-31, IV-G-09 stated that

the EPA has insufficient data to develop a standard for the

transmission and storage source category. The commenters

requested that the EPA delay the transmission and storage portion

of the rulemaking to properly survey the industry for more
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meaningful data, and assess whether a standard for the natural

gas transmission and storage source category is necessary or

achievable. According to commenter IV-D-07, the EPA would create

confusion "by leaving numerous questions unanswered and terms

undefined or interrelated with the proposed oil and gas

production standard" in its haste to develop a standard for the

natural gas transmission and storage source category

simultaneously with that of the production source category. 

Additionally, commenters IV-D-07 and IV-D-31 stated that the EPA

has proven a lack of information on this source category by

asking for emission point comments on reboiler vents, flash tanks

(GCG separators), storage vessels with flash potential, pipeline

pigging and storage of pipeline pigging wastes, and equipment

leaks.

Response: The EPA contacted potential stakeholders in the

initial phase of the development process for this NESHAP to

identify a list of interested stakeholders. The public record,

contained in EPA Air Docket A-94-04, has correspondence and

meeting summaries that show that the EPA had continual contact

with interested stakeholders, including representatives of the

natural gas transmission and storage source category. However,

to address industry concerns on the adequacy of the database used

in the development of proposed subpart HHH for natural gas

transmission and storage facilities, the EPA has collected

additional information on glycol dehydration units in the natural

gas transmission and storage source category. The EPA conducted

site visits to five natural gas transmission and storage

facilities to gain additional first-hand knowledge of the

processes and operations at existing facilities in this source

category. The EPA also met with stakeholders from the natural

gas transmission and storage industry to understand their

concerns. The EPA developed a questionnaire for distribution to

eight natural gas transmission and storage companies under the

authority of section 114 of the CAA. In the questionnaire, the

EPA requested data on the processes, operations, and control

technologies in use at existing natural gas transmission and
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storage facilities and relevant to the development of HAP

emissions standards for glycol dehydration units.

Through the questionnaire and site visits, the EPA collected

additional information on approximately 83 glycol dehydration

units 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, to develop a MACT floor

for process vents on glycol dehydration units located at existing

and new facilities in this source category.

On January 15, 1999, the EPA published a supplemental notice

announcing the availability of and to discuss the consideration

of, the additional information on the natural gas transmission

and storage source category collected by the EPA since proposal

(64 FR 2612). The additional data announced in the January 15,

supplemental notice included the following items located in Air

Docket A-94-04: (1) completed responses to the EPA’s section 114

survey questionnaire, items IV-G-24, and IV-G-26 through IV-G-32;

(2) site visit information, items IV-G-21, IV-G-22, and IV-G-25;

and (3) meeting summary of the meeting with representatives of

the Interstate Natural Gas Association of America, the Gas

Research Institute, and industry, item IV-E-02. The EPA has also

prepared analyses of these data, items IV-A-01, IV-A-02 and

IV-A-08.

Comment: Commenter IV-D-31 stated that the EPA

underestimated the impact of the proposed regulation on the

natural gas transmission and storage source category, due to the

EPA's lack of sufficient and representative information to

develop a MACT standard. The commenter contended that the EPA

underestimated the number of transmission and storage facilities

that would be affected by subpart HHH (five out of 2,000)

resulting in an underestimation of the cost impact. The

commenter suggested that the EPA postpone the natural gas

transmission and storage NESHAP (subpart HHH) to evaluate the

industry properly and to develop a better estimate of what the
30 True, W.R. Weather, Construction Inflation Could Squeeze

North American Pipelines. Oil & Gas Journal. pp. 33-56. August

31, 1998.

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MACT floor should be. The commenter offered to work with the EPA

on the development of a separate proposal.

Response: As stated in the previous response, in response

to comments on proposed subpart HHH, the EPA surveyed eight

natural gas transmission and storage companies under the

authority of section 114, conducted five site visits to

transmission and storage facilities, and received additional

information on 83 glycol dehydration units. In addition, the EPA

had data on 31 glycol dehydration units that was collected during

the development of the proposed NESHAP. According to the Oil and

Gas Journal,30 the total natural gas throughput handled by the

companies for which the Agency had information represented

approximately 14 percent of the total natural throughput for the

entire industry. Of the 114 glycol dehydration units for which

information was submitted, the EPA determined that one unit had

the potential to be an affected source under subpart HHH. 

Based on this information, the EPA projected the number of

affected sources to a nationwide value. Since the available data

represented approximately one seventh of the industry, the EPA

estimated that seven glycol dehydration units would be affected

sources. Although the MACT floor indicated that the best

performing 12 percent of the existing sources used combustion

(primarily flares) to control HAP emissions from the glycol

dehydration units, the EPA assumed that at least one of the

affected facilities would install a condensation unit to control

HAP emissions. Thus, the environmental and cost impacts were

based on six of the facilities installing a flare to meet the

requirements of subpart HHH and one would install a condenser.

Table 2.17-1 presents a summary of estimated environmental,

energy, and cost impacts for the natural gas transmission and

storage standards for existing major sources. The impacts were
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revised using the same approach that was used for the proposed

NESHAP. A detailed analysis regarding the estimated impacts of
2-224

TABLE 2.17-1

SUMMARY OF REVISED ESTIMATED ENVIRONMENTAL, ENERGY, AND COST

IMPACTS FOR THE NATURAL GAS TRANSMISSION AND STORAGE STANDARDS

FOR EXISTING MAJOR SOURCES*

Impact category

Existing Natural Gas

Transmission and

Storage*

Estimated number of impacted

facilities

7

Emission reductions (Mg/yr)

HAP 390

VOC 610

Methane 230

Secondary environmental emission 

increases (Mg/yr)

Sulfur oxides <1

Nitrogen oxides <1

Carbon monoxide <1

Energy (Kilowatt hours per year) None

Implementation costs (Million of July 1993 $)

Total installed capital 0.28

Total annual 0.3

* - No new major sources are anticipated for this source

category after the effective date for new sources and in the

first three years following promulgation of the rule.
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the NESHAP is presented in the docket (Air Docket A-94-04, number

IV-A-08).

Comment: Commenter IV-D-31 was concerned that the EPA is

regulating the natural gas transmission and storage industry

similarly to the oil and natural gas production industry. 

According to the commenter, the EPA's "skewed data collection

effort" resulted in a failure to make important distinctions

between the transmission and storage and the production segments

of the industry. The commenter was especially concerned about

the potential impact of subpart HHH on underground storage

facilities, as they are used to offset fluctuations in gas flow,

reduce natural gas costs, and improve reliability. Commenters

IV-D-07, IV-D-12, and IV-D-31 explained that a review of the

background information for this standard 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 oil production facilities that handled gas as a by-product

of oil production that have higher HAP emissions because they

handle more liquids with higher concentrations of HAP. 

Furthermore, commenters IV-D-31 and IV-G-12 also noted that once

the gas reaches the transmission and storage facilities, it has

been dehydrated at least once, further lowering the

concentrations of HAP. Commenter IV-G-12 also mentioned that

exposing processed gas to ground water in a storage facility can

increase the moisture content and require additional dehydration,

but it does not necessary increase BTEX in the gas. The

commenter referred to the GLYCalc manual for discussion of impact

of BTEX concentration in the gas on dehydrator emissions.

Commenters IV-D-10 and IV-G-12 recommended changes in the

exemptions for transmission and storage facilities. Commenter

IV-D-10 requested that the size cutoff for transmission and

storage be higher than that for production, since HAP emissions

at transmission and storage facilities are generally much lower

than production facilities. Commenter IV-G-12 recommended that
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the subpart HHH provide an exemption for transmission and storage

facilities where the BTEX concentrations of the stored gas fall

below a minimum threshold and it can be shown that the act of

storing the gas does not cause an increase in the concentration

of the BTEX in the gas when it is retrieved from storage. The

commenter further explained that dehydrators serving transmission

and storage facilities are fundamentally different from those

located at production wells. 

Response: In the proposal, glycol dehydration units

operating at an actual annual average natural gas throughput less

than 3 MMscf/d or having actual average benzene emissions less

than 1 tpy were exempt from the control requirements. The EPA

evaluated the data collected for 114 glycol dehydration units in

the natural gas transmission and storage source category to

determine whether there was a natural gas throughput level, or a

benzene emission level for which glycol dehydration units

operating below this level were not controlled.

In the new data, the Agency did not identify evidence to

suggest that glycol dehydration units operating with actual

annual average natural gas throughput rates less than 10 MMscf/d

or having actual benzene emissions less than 1 tpy are controlled

at the MACT floor and it was not cost effective to go beyond the

floor for these glycol dehydration units.

In addition, the Agency does not have any information

indicating that there are any sources in the natural gas

transmission and storage source category operating below

10 MMscf/d or having benzene emissions less than 1 tpy that have

emissions greater than the major source thresholds of 10 tpy for

individual HAP or 25 tpy for any combination of HAP.

Therefore, the final subpart HHH exempts each glycol

dehydration unit with an annual actual average natural gas

throughput less than 10 MMscf/d or actual average benzene

emissions less than 1 tpy from the control requirements. 

Comment: Commenter IV-D-31 stated that they believe that

the EPA lacks sufficient and representative information on the

natural gas transmission and storage source category to determine
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a MACT floor. The commenter noted that only one transmission

facility, and no underground storage facilities, was surveyed. 

The commenter recommended that the EPA revise its MACT floor

determination for transmission and storage dehydration units. 

The commenter suggested that the EPA did not include the

additional cost that would be required to send personnel to

remote, unmanned transmission and storage facilities to

demonstrate compliance based on short averaging periods. The

commenter stated that a longer averaging period would also be

more practical and cost-effective, and more likely to be

achievable by the best performing sources. The commenter asked

the EPA to take the time to gather the information required to

properly evaluate what is actually achieved by emission points in

the natural gas transmission and storage source category.

Response: According to the information collected from 114

glycol dehydration units through the section 114 questionnaire,

site visits, and data previously collected during the development

of the proposed standards, 71 glycol dehydration units are

controlled. Fifty-nine of these units utilize combustion as the

control technology for process vents on glycol dehydration units. 

Of these, 51 utilize flares, seven utilize enclosed combustion

devices, and one uses an in-stack flare system. Seven units

utilize a combination of condensation and combustion to control

glycol dehydration unit process vents and five utilize

condensation.

The MACT floor analysis for the natural gas transmission and

storage source category was based on information available on the

top 14 performing glycol dehydration units, which corresponds to

12 percent of 114 glycol dehydration units.

The EPA compared the control level data for the top 14

performing units to the proposed control level of 95 percent for

process vents on glycol dehydration units at existing and new

natural gas transmission and storage facilities. The available

information indicates that the best performing 12 percent of the

facilities, i.e., 14 units, utilize some form of combustion and

achieve a HAP emission reduction of at least 98 percent. 
2-228

However, among all sources that apply combustion, the reported

control efficiency ranged from 95 to 98 percent. The EPA was

unable to determine the technical basis for the reported

differences in the control efficiencies for these combustion

devices. Therefore, in order to account for the observed

variability in HAP emission reduction efficiency, the final rule

requires 95 percent as the HAP emission reduction for this source

category associated with this technology.

Under the proposed standards, the MACT floor for new sources

was the same as the MACT floor for existing sources (i.e., 95-

percent control). In the review of the new additional

information, the EPA did not identify a method of control

applicable to all types of new sources that would achieve a

greater level of HAP emission reduction than the MACT floor for

existing sources. Therefore, as with the proposal, the EPA

determined that the MACT floor for new sources in the natural gas

transmission and storage source category was the same as the MACT

floor for existing sources.

Comment: Commenter IV-D-31 supported the aggregation of

equipment at compressor stations and single wells, with their

associated equipment, for major source determinations. However,

the commenter explained that natural gas storage fields cover

large areas and operations are based on depleted production

fields with the same surface separation of facilities as existing

production fields. Therefore, the commenter, along with commenter

IV-D-04, stated that aggregating emission sources at natural gas

storage facilities for major source determinations is

inconsistent with the meaning of section 112(n)(4)(A) of the CAA

and that aggregating emission sources at these facilities

suggests that the EPA has insufficient data regarding natural gas

storage facilities. The commenters explained that glycol

dehydrators at storage facilities do not emit significant

quantities of HAP because the natural gas has been processed or

dehydrated before it is injected into the storage fields, and has

small amounts of HAP and VOC. According to the commenters,

aggregating affected sources over large gas storage fields could
2-229

result in major source determinations and the controls on each

contributing affected source would be more expensive than the EPA

has estimated, for small amounts of HAP reduction. The commenters

recommended that the EPA collect data to characterize natural gas

storage operations better. 

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

". . .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 . . .."

The EPA has interpreted this provision to mean that individual

pipeline compressor or pump stations shall not be aggregated with

emissions from other stations. Nothing in the

section 112(n)(4)(A) provisions refers to natural gas storage

facilities as those facilities for which emission aggregation is

not allowed. Additionally, the definition of major source in

§63.1271 states that emissions from processes, operations, or

equipment that are not part of the same facility shall not be

aggregated. Based on the EPA's knowledge of the industry,

storage fields should have well-defined surface sites, preventing

large areas from being considered part of the same facility.

Comment: Commenters IV-D-10 and IV-D-31 requested that the

deadline for promulgation of the transmission and storage

standard be changed from November 15, 1997 to November 15, 2000. 

The commenters noted that transmission and storage is a new

source category.

Response: The EPA amended the source category list to add

the natural gas transmission and storage source category as a

major source category and proposed a regulation that would apply

to major sources in this source category. As stated in section

112(c)(5) of the Clean Air Act as Amended in 1990 on the addition

of source categories

". . .emission standards under subsection (d) for the

category or subcategory shall be shall be promulgated

within 10 years after enactment of the Clean Air Act

Amendments of 1990, or within 2 years after the date on

which such category or subcategory is listed, whichever

is later."
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Although the natural gas transmission and storage source category

is in the 10-year bin of source categories, by promulgating the

proposed regulation on the current schedule, the EPA is complying

with the requirements of the CAA. 

Comment: Commenters IV-D-07 and IV-D-31 stated that the

definition of natural gas transmission is misleading and mixes

production terms with natural gas transmission terms. For

example, "boosters" are only used on production lines. The

commenters further remarked they did not understand the phrase

"used for long distance transport" since "long distance" is not

defined. The commenters recommended that the EPA use the

Department of Transportation's definitions (49 CFR 192.3) for

such terms as pipeline, transmission line, and transportation of

natural gas.

Response: The EPA does not believe that further

clarification of the definition for natural gas transmission is

necessary. The definition of natural gas transmission in

§63.1271 of subpart HHH was developed in consultation with

stakeholders in the natural gas transmission and storage source

category (Air Docket A-94-04 Numbers II-C-4, II-C-5, and

II-D-53). As requested by the stakeholders, this definition is

consistent with the definition used by the Federal Energy

Regulatory Commission and adequately reflects the actual workings

of the industry.

In addition, the EPA's understanding is that natural gas

transmission pipelines differ from natural gas mains in that they

typically operate at higher pressure, are longer, and the

distance between connections is greater. Therefore, the EPA has

retained the phrase "long distance transport" to maintain this

distinction.

Comment: Commenter IV-D-16 stated that the term associated

equipment does not need to be defined in subpart HHH since

production sources are not covered. Commenter IV-D-35 agreed with

proposed definition of associated equipment.

Response: The EPA agrees that the term associated equipment

is unnecessary and has removed this term from §63.1271 of subpart
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HHH. In addition, the EPA has revised the definition of major

source in §63.1271 as follows:

Major source, as used in this subpart, shall have

the same meaning as in §63.2, except that:

(1) Emissions from any oil or gas exploration or

production well (with its associated equipment)

andemissions from any pipeline compressor or pump

station shall not be aggregated with emissions from

other similar stationsunits, 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.

Comment: Commenter IV-D-16 stated that a compressor station

is defined in §63.1271 as equipment that "...supplies energy to

move natural gas at increased pressure from fields. . . ." The

commenter requested that the reference to fields be deleted since

subpart HHH does not cover production sites (i.e., fields).

Response: As suggested by the commenter, subpart HHH does

not encompass production sites. However, it is possible for

compressors, located in the transmission and storage source

category, to move natural gas from production fields. 

Furthermore, the EPA developed this definition based on standard

industry nomenclature. Therefore, the EPA does not believe that

the change recommended by the commenter is warranted.
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2.18 COMMENTS RECEIVED ON THE JANUARY 15, 1999 SUPPLEMENTAL

NOTICE (64 FR 2611)

Comment: Commenters IV-G-38 and IV-G-37 indicated that they

did not agree with a MACT floor of 95 percent for the

transmission and storage source category. The commenters stated

that capital expenditures had been made to control some existing

dehydrators with condensers and that it would be unreasonable to

require these sources to meet a MACT floor based on a different

technology. 

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 the data

show 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. 

In addition, commenter IV-G-36 stated that the 95 percent control

level cannot be continuously achieved by the use of condensers

alone.

Response: The EPA does not believe that it is appropriate

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 " . . . 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 percent. Furthermore,

the data indicated that the top 12 percent of the existing glycol

dehydration units were controlled using combustion or a
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combination of combustion and condensation. Therefore, in

accordance with the statute, the EPA established the MACT floor

to be 95 percent for glycol dehydration units located at natural

gas transmission and storage facilities, which corresponds to

combustion.

With regard to the comment regarding continuous compliance,

in the supplemental notice the EPA did not address the issue of

averaging period for condensers in use at transmission and

storage facilities. The final subpart HHH 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-percent HAP emission reduction on a 30-day rolling average. 

In addition, the final subpart HHH allows the owner or operator

to comply with: (1) 95 percent HAP emission reduction,

(2) 20 ppmv outlet HAP concentration for combustion devices, or

(3) outlet emissions of 1 tpy of benzene. The EPA believes that

the 1 tpy benzene emission limit and the 30-day averaging period

for condensers provides sufficient flexibility for owners and

operators of existing controlled glycol dehydration units.

Comment: Commenters IV-G-37 and IV-G-38 referred to the

proposed rule (63 FR 6288), which provided a 20 ppmv outlet HAP

concentration limit for combustion devices. The commenters

stated that the EPA did not provide rationale for dropping this

limitation and requested that it be retained.

Response: The EPA did not drop the 20 ppmv requirement for

combustion devices. The final rule requires owners or operators

to meet: (1) a 95-percent HAP emission reduction, (2) a 20 ppmv

outlet HAP concentration limit for combustion devices, or (3) a

1 tpy outlet benzene emission limit.

Comment: Commenters IV-G-37, IV-G-38 ,and IV-G-39 agreed

that exempting glycol dehydration units with actual annual

average natural gas throughputs less than 283 thousand m3/day

from the control requirements under subpart HHH was appropriate. 

Commenters IV-G-37 and IV-G-38 stated that they were unaware of

any dehydration units that operate at the higher flow rate that

would exceed the HAP emission cut-off. In contrast, commenter
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IV-G-36 stated that a cutoff level of 10 MMscf/d would provide no

significant relief to the majority of companies in the

transmission and storage segment of the industry. Although they

supported the change in the level for the cutoff, the commenter

stated that dehydration units of this size would probably be

exempt from the controls based on the criteria for major sources.

Response: The EPA appreciates the commenters' support and

the EPA believes that the cutoff level of 10 MMscf/d, which is

based on the MACT floor determination, is appropriate for this

industry. However, commenter IV-G-36 was incorrect in stating

that dehydration units with natural gas throughput less than 10

MMscf/d would be exempt from controls based on the criteria for

major source. This statement is true if the glycol dehydration

unit is the only HAP emission source located at the facility. 

However, if the facility is determined to be major source due to

the aggregation of all HAP emission sources located at the

facility, then the owner or operator must comply with the control

requirements for each glycol dehydration unit at that facility. 

Thus, only glycol dehydration units that have natural gas

throughput less than 10 MMscf/d are exempt from control

requirements at the major source.

Commenter: Commenter IV-G-36 referred to Section I

(Background) of the supplemental notice, which indicated that the

original data included a questionnaire to one company with 31

glycol dehydration units. The commenter stated that they had

assumed that this corresponds to the September 15, 1993 entry

noted in table A-1 of the BID, Questionnaire to CNG Transmission

Corporation.

Response: The commenter's assumption is correct. The EPA

surveyed CNG Transmission Corporation and received information

for 31 glycol dehydration units.

Comment: Commenter IV-G-36 reviewed the docket items listed

in the supplemental notice as containing the information used by

the Agency to evaluate the transmission and storage source

category (Air Docket A-94-04 Numbers IV-E-02, IV-G-21, IV-G-22,

and IV-G-24 through 32). The information contained in item
2-235

IV-G-26 was deemed to be confidential. The commenter stated that

the data they were able to review indicated that there were 89

additional glycol dehydration units, 14 of which were noted as

having emission controls. The commenter stated that it was

unclear how the EPA derived the numbers presented in Section III

(MACT Floor for Existing Sources) regarding the total number of

units and the number of controlled units. According to the

commenter, the data they were able to review indicated that there

are a minimum of 120 dehydration units (instead of the 112

reported by the EPA) of which 14 have been identified as having

controls (instead of 69 as reported by the EPA). Furthermore,

the commenter indicated that there was a discrepancy in the types

of controls being utilized. However, the commenter also noted

that the data on the original 31 units and the confidential

information contained in docket number IV-G-26 were not reviewed.

Response: The discrepancy in the number of units that the

commenter identified and the number of units reported in the

supplemental notice resulted from the information not reviewed by

the commenter including: the confidential information (i.e.,

information contained in site visit reports, and the information

collected from one company under the authority of section 114),

the information collected during the development of the proposal,

as well as the number of units for which no information was

submitted as instructed in the section 114 questionnaire. 

Table 2.18-1 presents a summary of the information collected to

identify the number of existing glycol dehydration units and the

types of controls in use. As shown in the table, the EPA used

three sources of information: section 114 questionnaire (data

received 12/93), site visits (conducted in 10/98), and section

114 questionnaires (data received 10/98).

The number of glycol dehydration units identified in the

response to the section 114 questionnaire in December 1993 is

contained in the docket (Air Docket A-94-04 number II-D-26).

The data collected under the October 1998 section 114

questionnaire is also contained in the docket (Air Docket A-94-04 
2-236

TABLE 2.18-1 SUMMARY OF THE INFORMATION COLLECTED FOR GLYCOL DEHYDRATION 

NATURAL GAS TRANSMISSION AND STORAGE SOURCE CATEGORY

Source of

Information

Total

Number of

Dehydration

Units

Identified

Number of

Dehydration

Units for

Which

Information

was

Provided

Number of Dehydration Units that are

Controlled (by Control Technology) 

Flares 

Enclosed

Combustion

Combustion

and

Condensation Condensati

Response toSection 114questionnaire(data received12/93)

31 31 21 0 0 0 

Site Visitsa 7 7 10 1 5 

Response toSection 114questionnaire(data received10/98)b,c

106 76 30 7 6 0 

Total 144 114 52 7 7 5 

a Five facilities were visited, seven glycol dehydration units were identified. Site visit reports are contained 

A-94-04, numbers IV-B-01 through IV-B-05. b Respondents were required to identify all dehydration units and submit information for dehydration units whose 

was greater than 15 MMscf/d. Two respondents reported information for their dehydration units whose natural gas than 15 MMscf/d. There were 30 dehydration units identified for which no information was provided.

c Information contained in docket A-94-04, item IV-G-26 represents 61 glycol dehydration units, of which informat

46 units and 34 of these are controlled.
31 The commenters referred to the following draft report:

"BTEX Emission from T&S Industry Segment Glycol Dehydrator." 

July 27, 1998, by Radian International LLC. Conversations with

the commenters (Air Docket A-94-04 numbers IV-A-10 and IV-A-11)

indicated that the final report title is "Glycol Dehydrator

Emissions when Treating Low-BTEX Gas." November 5, 1998.

2-237

numbers IV-G-24 and IV-G-26 through 32). Respondents to the

October 1998 section 114 questionnaire were instructed to submit

all information on glycol dehydration units that have natural gas

throughputs greater than 15 MMscf/d. Respondents were also

instructed that the requested information was not required for

each glycol dehydration unit where the natural gas throughput was

less than 15 MMscf/d, but could be submitted if available. The

respondents identified 30 glycol dehydration units that had

natural gas throughputs less than 15 MMscf/d, and no information

was submitted for these units (it should be noted that

information was provided for three glycol dehydration units for

which the natural gas throughput was less than 15 MMscf/d).

In addition, while reviewing the number of dehydration units

for which the EPA had information, the EPA identified two

additional glycol dehydration units, both of which were

controlled (Air Docket A-94-04 numbers IV-G-21, IV-G-22, and

IV-G-25). Therefore, the total number of glycol dehydration

units for which the EPA has information is 114 (compared to 112

as stated in the January 15 supplemental notice).

Comment: Commenters IV-G-36, IV-G-37, and IV-G-38 referred

to a GRI report31 which stated that condensers could not

consistently achieve a 95-percent reduction of HAP. The

commenters indicated that this report had been submitted to the

EPA and was included in the regulatory record. Commenters

IV-G-37 and IV-G-38 stated that in the supplemental notice, the

EPA did not present information refuting that condensers may not

achieve the proposed HAP emission reduction, but had instead

chosen to change the technological basis for the MACT floor for

existing and new sources.
2-238

Commenter IV-G-36 was concerned that the EPA did not

consider all of the information when evaluating the proposed

standards. The commenter stated the information, compiled by GRI

regarding emission levels as functions of gas throughput, gas

temperature, gas pressure, water content, and BTEX concentration,

was not contained in the docket and should be included and

considered by the EPA. The commenter indicated that since this

information was not referenced in the supplemental notice, it is

likely that the EPA did not give this data due consideration. 

The commenter stated that the EPA needs to consider all available

data when establishing industry standards.

Response: The GRI report referred to by the commenters was

not submitted to the EPA, and therefore was not included in the

docket prior to the supplemental notice. However, since the

publication of the supplemental notice, the EPA has obtained a

copy of this report, and has reviewed its content (the report is

available on the Internet at the following address:

http://www.gri.org/pub/content/nov/19981105/115012/lowbtex_dehys.html).

As stated in previous responses, the MACT floor for the

transmission and storage source category was developed based on

data collected in response to comments on the proposed

subpart HHH, as well as data collected prior to proposal. The

EPA determined the MACT floor for this source category to be

95-percent emission reduction. Furthermore, at least 93 percent

of the existing glycol dehydration units that are controlled, for

which the EPA had data (66 dehydration units out of 71 controlled

units) employed combustion in some form (i.e., flares, enclosed

combustion, or a combination of combustion and condensation) and

achieve at least a 95-percent emission reduction (see

table 2.18 1) .

Since most existing sources are controlled using combustion,

and by providing a 30-day averaging period and a 1-tpy benzene

emission limitation, the EPA believes that the commenter's

concerns about condenser performance have been addressed. 
2-239

Therefore, the EPA has not made any modifications to subpart HHH

in response to these comments.
TECHNICAL REPORT DATA

(Please read Instructions on reverse before completing)

1. REPORT NO.

 EPA-453/R-99-004b

2. 3. RECIPIENT'S ACCESSION NO.

4. TITLE AND SUBTITLE

 National Emission 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 

5. REPORT DATE

 May 1999

6. PERFORMING ORGANIZATION CODE

7. AUTHOR(S)

 

8. PERFORMING ORGANIZATION REPORT NO.

9. PERFORMING ORGANIZATION NAME AND ADDRESS

 Emission Standards Division (Mail Drop 13)

 Office of Air Quality Planning and Standards

 U.S. Environmental Protection Agency

 Research Triangle Park, NC 27711

10. PROGRAM ELEMENT NO.

11. CONTRACT/GRANT NO.

 68-D6-0008

12. SPONSORING AGENCY NAME AND ADDRESS

 Director

 Office of Air Quality Planning and Standards

 Office of Air and Radiation

 U.S. Environmental Protection Agency

 Research Triangle Park, NC 27711

13. TYPE OF REPORT AND PERIOD COVERED

 

14. SPONSORING AGENCY CODE

 EPA/200/04

15. SUPPLEMENTARY NOTES

 

16. ABSTRACT

 This document contains a summary of public comments received on the NESHAP for Oil and Natural

Gas Production and Natural Gas Transmission and Storage (40 CFR 63, subparts HH and HHH), which

were proposed on February 6, 1998 (63 FR 6288). This document also provides the EPA’s response to

each comment, and outlines the changes made to the regulation in response to public comments.

17. KEY WORDS AND DOCUMENT ANALYSIS

a. DESCRIPTORS b. IDENTIFIERS/OPEN ENDED TERMS c. COSATI

Field/Group

 Environmental Protection, Air Pollution Control, Air

Emissions Control, Associated Equipment, Black Oil,

Condensate, Custody Transfer, Equipment Leaks,

Glycol Dehydration Units, Hazardous Air Pollutants,

Hazardous Substances, Natural Gas Transmission and

Storage, Oil and Natural Gas Production

Pipelines, Organic Liquids Distribution (non-gasoline),

Reporting and Recordkeeping Requirements, Storage

Vessels, Tank batteries, Tanks, Triethylene Glycol

Hazardous air pollutants

18. DISTRIBUTION STATEMENT

 Release Unlimited

19. SECURITY CLASS (Report)

 Unclassified

21. NO. OF PAGES

285

20. SECURITY CLASS (Page)

 Unclassified

22. PRICE

EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION IS OBSOLETE