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6560-50-P

E.O. 12866 NSPS and NESHAP: Oil and Natural Gas Production, 

Transmission and Distribution 2060-AP76 Proposal 20110728

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2010-0505; FRL- ]

 

RIN 2060-AP76

Standards of Performance for New Stationary Sources: Oil 

and Natural Gas Production and Natural Gas Transmission and 

Distribution; National Emission Standards for Hazardous Air 

Pollutants From Oil and Natural Gas Production Facilities; 

and National Emission Standards for Hazardous Air 

Pollutants From Natural Gas Transmission and Storage

Facilities

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

SUMMARY: This action announces how the EPA will address the 

reviews of the new source performance standards for 

volatile organic compound and sulfur dioxide emissions from 

natural gas processing plants. We are adding to the source 

category list any oil and gas operation not covered by the 

current listing. This action also includes proposed 

amendments to the existing new source performance standards 

for volatile organic compounds from natural gas processing 

plants and proposed standards for operations that are not 

covered by the existing new source performance standards. 

In addition, this action proposes how the EPA will address 
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the residual risk and technology review conducted for the

oil and natural gas production and natural gas transmission 

and storage national emission standards for hazardous air 

pollutants. This action further proposes standards for 

emission sources within these two source categories that 

are not currently addressed, as well as amendments to 

improve aspects of these national emission standards for 

hazardous air pollutants related to applicability and 

implementation. Finally, this action addresses provisions 

in these new source performance standards and national 

emission standards for hazardous air pollutants related to 

emissions during periods of startup, shutdown and 

malfunction.

DATES: Comments must be received on or before [INSERT DATE 

60 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 

Public Hearing. Three public hearings will be held to 

provide the public an opportunity to provide comments on 

this proposed rulemaking. One will be held in the Dallas, 

Texas area, on [INSERT DATE], one in Pittsburgh, 

Pennsylvania, on [INSERT DATE], and one in Denver, 

Colorado, on [INSERT DATE]. Each hearing will convene at 

10:00 a.m. local time. For additional information on the 
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public hearings and requesting to speak, see the 

SUPPLEMENTARY INFORMATION section of this preamble.

ADDRESSES: Submit your comments, identified by Docket ID 

Number EPA-HQ-OAR-2010-0505, by one of the following 

methods:

• Federal eRulemaking Portal: 

http://www.regulations.gov: Follow the 

instructions for submitting comments.

• Agency Website: 

http://www.epa.gov/oar/docket.html. Follow the 

instructions for submitting comments on the Air 

and Radiation Docket website.

• Email: a-and-r-docket@epa.gov. Include Docket ID 

Number EPA-HQ-OAR-2010-0505 in the subject line 

of the message.

• Facsimile: (202) 566-9744.

• Mail: Attention Docket ID Number EPA-HQ-OAR-2010-

0505, 1200 Pennsylvania Ave., NW, Washington, DC 

20460. Please include a total of two copies. In 

addition, please mail a copy of your comments on 

the information collection provisions to the 

Office of Information and Regulatory Affairs, 

Office of Management and Budget (OMB), Attn: Desk 
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Officer for the EPA, 725 17th Street, NW, 

Washington, DC 20503.

• Hand Delivery: United States Environmental 

Protection Agency, EPA West (Air Docket), Room 

3334, 1301 Constitution Ave., NW, Washington, DC 

20004, Attention Docket ID Number EPA-HQ-OAR2010-0505. Such deliveries are only accepted 

during the Docket’s normal hours of operation, 

and special arrangements should be made for 

deliveries of boxed information.

Instructions: Direct your comments to Docket ID Number EPAHQ-OAR-2010-0505. The EPA’s policy is that all comments 

received will be included in the public docket without 

change and may be made available online at 

http://www.regulations.gov, including any personal 

information provided, unless the comment includes 

information claimed to be confidential business information

(CBI) or other information whose disclosure is restricted 

by statute. Do not submit information that you consider to 

be CBI or otherwise protected through www.regulations.gov

or email. The www.regulations.gov website is an “anonymous 

access” system, which means the EPA will not know your 

identity or contact information unless you provide it in 
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the body of your comment. If you send an email comment 

directly to the EPA without going through 

www.regulations.gov, your email address will be 

automatically captured and included as part of the comment 

that is placed in the public docket and made available on 

the Internet. If you submit an electronic comment, the EPA 

recommends that you include your name and other contact 

information in the body of your comment and with any disk 

or CD-ROM you submit. If the EPA cannot read your comment 

due to technical difficulties and cannot contact you for 

clarification, the EPA may not be able to consider your 

comment. Electronic files should avoid the use of special 

characters, any form of encryption, and be free of any 

defects or viruses. For additional information about the 

EPA’s public docket, visit the EPA Docket Center homepage 

at http://www.epa.gov/epahome/dockets.htm. For additional 

instructions on submitting comments, go to section II.C of 

the SUPPLEMENTARY INFORMATION section of this preamble.

Docket: All documents in the docket are listed in the 

www.regulations.gov index. Although listed in the index, 

some information is not publicly available, e.g., CBI or 

other information whose disclosure is restricted by 

statute. Certain other material, such as copyrighted 
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material, is not placed on the Internet and will be 

publicly available only in hard copy. Publicly available 

docket materials are available either electronically 

through www.regulations.gov or in hard copy at the U.S. 

Environmental Protection Agency, EPA West (Air Docket), 

Room 3334, 1301 Constitution Ave., NW, Washington, DC

20004. The Public Reading Room is open from 8:30 a.m. to 

4:30 p.m., Monday through Friday, excluding legal holidays. 

The telephone number for the Public Reading Room is (202) 

566-1744, and the telephone number for the Air Docket is 

(202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Bruce Moore, Sector 

Policies and Programs Division, Office of Air Quality 

Planning and Standards (E143-01), Environmental Protection 

Agency, Research Triangle Park, North Carolina 27711, 

telephone number: (919) 541-5460; facsimile number: (919) 

685-3200; email address: moore.bruce@epa.gov. 

SUPPLEMENTARY INFORMATION:

Organization of This Document. The following outline is 

provided to aid in locating information in this preamble.

I. Preamble Acronyms and Abbreviations

II. General Information

A. Does this action apply to me?

B. Where can I get a copy of this document and other

 related information?

C. What should I consider as I prepare my comments for
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 the EPA?

D. When will a public hearing occur?

III. Background Information

A. What are standards of performance and NSPS?

B. What are NESHAP?

C. What litigation is related to this proposed action?

D. What is a sector-based approach?

IV. Oil and Natural Gas Sector

V. Summary of Proposed Decisions and Actions

A. What are the proposed revisions to the NSPS?

B. What are the proposed decisions and actions related

 to the NESHAP?

C. What are the proposed notification, recordkeeping and

 reporting requirements for this proposed action?

D. What are the innovative compliance approaches being 

 considered?

E. How does the NSPS relate to permitting of sources?

VI. Rationale for Proposed Action for NSPS

A. What did we evaluate relative to NSPS?

B. What are the results of our evaluations and proposed

 actions relative to NSPS?

VII. Rationale for Proposed Action for NESHAP

A. What data were used for the NESHAP analyses?

B. What are the proposed decisions regarding certain

 unregulated emissions sources?

C. How did we perform the risk assessment and what are 

 the results and proposed decisions?

D. How did we perform the technology review and what are

 the results and proposed decisions?

E. What other actions are we proposing?

VIII. What are the cost, environmental, energy and

 economic impacts of the proposed 40 CFR part 60, 

 subpart OOOO and amendments to subparts HH and HHH of 

 40 CFR part 63?

A. What are the affected sources?

B. How are the impacts for this proposal evaluated?

C. What are the air quality impacts?

D. What are the water quality and solid waste impacts?

E. What are the secondary impacts?

F. What are the energy impacts?

G. What are the cost impacts?

H. What are the economic impacts?

I. What are the benefits?

IX. Request for Comments

X. Submitting Data Corrections

XI. Statutory and Executive Order Reviews
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A. Executive Order 12866: Regulatory Planning and

 Review and Executive Order 13563: Improving Regulation 

 and Regulatory Review

B. Paperwork Reduction Act

C. Regulatory Flexibility Act

D. Unfunded Mandates Reform Act

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination 

 with Indian Tribal Governments

G. Executive Order 13045: Protection of Children from

 Environmental Health and Safety Risks

H. Executive Order 13211: Actions Concerning Regulations 

 That Significantly Affect Energy Supply, Distribution, 

 or Use

I. National Technology Transfer and Advancement Act

J. Executive Order 12898: Federal Actions to Address 

 Environmental Justice in Minority Populations and Low-

 Income Populations

I. Preamble Acronyms and Abbreviations

Several acronyms and terms used to describe industrial 

processes, data inventories and risk modeling are included 

in this preamble. While this may not be an exhaustive list, 

to ease the reading of this preamble and for reference 

purposes, the following terms and acronyms are defined 

here:

ACGIH American Conference of Governmental Industrial 

Hygienists

ADAF Age-Dependent Adjustment Factors

AEGL Acute Exposure Guideline Levels 

AERMOD The air dispersion model used by the HEM-3 model

API American Petroleum Institute

BACT Best Available Control Technology 

BID Background Information Document

BPD Barrels Per Day

BSER Best System of Emission Reduction

BTEX Benzene, Ethylbenzene, Toluene and Xylene

CAA Clean Air Act

CalEPA California Environmental Protection Agency
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CBI Confidential Business Information

CEM Continuous Emissions Monitoring

CEMS Continuous Emissions Monitoring System

CFR Code of Federal Regulations

CIIT Chemical Industry Institute of Toxicology

CO Carbon Monoxide

CO2 Carbon Dioxide

CO2e Carbon Dioxide Equivalent

DOE Department of Energy

ECHO Enforcement and Compliance History Online

e-GGRT Electronic Greenhouse Gas Reporting Tool

EJ Environmental Justice

EPA Environmental Protection Agency

ERPG Emergency Response Planning Guidelines 

ERT Electronic Reporting Tool

GCG Gas Condensate Glycol 

GHG Greenhouse Gas

GOR Gas to Oil Ratio

GWP Global Warming Potential

HAP Hazardous Air Pollutants

HEM-3 Human Exposure Model, version 3

HI Hazard Index

HP Horsepower

HQ Hazard Quotient

H2S Hydrogen Sulfide

ICR Information Collection Request

IPCC Intergovernmental Panel on Climate Change 

IRIS Integrated Risk Information System

km Kilometer

kW Kilowatts

LAER Lowest Achievable Emission Rate

lb Pounds

LDAR Leak Detection and Repair

MACT Maximum Achievable Control Technology

MACT Code Code within the NEI used to identify processes

included in a source category

Mcf Thousand Cubic Feet

Mg/yr Megagrams per year

MIR Maximum Individual Risk

MIRR Monitoring, Inspection, Recordkeeping and 

Reporting

MMtCO2e Million Metric Tons of Carbon Dioxide 

Equivalents

NAAQS National Ambient Air Quality Standards
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NAC/AEGL National Advisory Committee for Acute Exposure 

Guideline Levels for Hazardous Substances 

NAICS North American Industry Classification System

NAS National Academy of Sciences

NATA National Air Toxics Assessment

NEI National Emissions Inventory

NEMS National Energy Modeling System

NESHAP National Emissions Standards for Hazardous Air 

Pollutants

NGL Natural Gas Liquids

NIOSH National Institutes for Occupational Safety 

and Health

NOx Oxides of Nitrogen

NRC National Research Council

NSPS New Source Performance Standards

NSR New Source Review 

NTTAA National Technology Transfer and Advancement Act

OAQPS Office of Air Quality Planning and Standards

OMB Office of Management and Budget

PB-HAP Hazardous air pollutants known to be persistent 

and bio-accumulative in the environment

PFE Potential for Flash Emissions

PM Particulate Matter

PM2.5 Particulate Matter (2.5 microns and less)

POM Polycyclic Organic Matter

PPM Parts Per Million

PPMV Parts Per Million by Volume

PSIG Pounds per square inch gauge

PTE Potential to Emit

QA Quality Assurance

RACT Reasonably Available Control Technology

RBLC RACT/BACT/LAER Clearinghouse 

REC Reduced Emissions Completions

REL CalEPA Reference Exposure Level

RFA Regulatory Flexibility Act

RfC Reference Concentration

RfD Reference Dose

RIA Regulatory Impact Analysis 

RICE Reciprocating Internal Combustion Engines

RTR Residual Risk and Technology Review

SAB Science Advisory Board

SBREFA Small Business Regulatory Enforcement Fairness 

Act

SCC Source Classification Codes

SCFH Standard Cubic Feet Per Hour

SCFM Standard Cubic Feet Per Minute
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SCM Standard Cubic Meters

SCMD Standard Cubic Meters Per Day

SCOT Shell Claus Offgas Treatment

SIP State Implementation Plan

SISNOSE Significant Economic Impact on a Substantial 

Number of Small Entities

S/L/T State and Local and Tribal Agencies

SO2 Sulfur Dioxide

SSM Startup, Shutdown and Malfunction

STEL Short-term Exposure Limit

TLV Threshold Limit Value

TOSHI Target Organ-Specific Hazard Index

TPY Tons per Year

TRIM Total Risk Integrated Modeling System

TRIM.FaTE A spatially explicit, compartmental mass balance 

model that describes the movement and 

transformation of pollutants over time, through 

a user-defined, bounded system that includes 

both biotic and abiotic compartments

TSD Technical Support Document

UF Uncertainty Factor

UMRA Unfunded Mandates Reform Act

URE Unit Risk Estimate

VCS Voluntary Consensus Standards

VOC Volatile Organic Compounds

VRU Vapor Recovery Unit

II. General Information

A. Does this action apply to me?

The regulated industrial source categories that are 

the subject of this proposal are listed in Table 1 of this 

preamble. These standards and any changes considered in 

this rulemaking would be directly applicable to sources as 

a Federal program. Thus, Federal, state, local and tribal 

government entities are not affected by this proposed 

action. 
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TABLE 1. INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS 

PROPOSED ACTION

Category NAICS 

code1

Examples of regulated

entities

Industry . . . .

211111 Crude Petroleum and Natural 

Gas Extraction

211112 Natural Gas Liquid 

Extraction

221210 Natural Gas Distribution

486110 Pipeline Distribution of 

Crude Oil

486210 Pipeline Transportation of 

Natural Gas

Federal government . . . . Not affected.

State/local/tribal 

government

. . . . Not affected.

1 North American Industry Classification System.

 

This table is not intended to be exhaustive, but 

rather provides a guide for readers regarding entities 

likely to be affected by this action. To determine whether 

your facility would be regulated by this action, you should 

examine the applicability criteria in the regulations. If 

you have any questions regarding the applicability of this 

action to a particular entity, contact the person listed in 

the preceding FOR FURTHER INFORMATION CONTACT section.

B. Where can I get a copy of this document and other 

related information?

In addition to being available in the docket, an 

electronic copy of this proposal will also be available on 
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the EPA’s website. Following signature by the EPA 

Administrator, a copy of this proposed action will be 

posted on the EPA’s website at the following address: 

http://www.epa.gov/airquality/oilandgas.

Additional information is available on the EPA’s 

Residual Risk and Technology Review (RTR) website at 

http://www.epa.gov/ttn/atw/rrisk/oarpg.html. This 

information includes the most recent version of the rule, 

source category descriptions, detailed emissions and other 

data that were used as inputs to the risk assessments.

C. What should I consider as I prepare my comments for the 

EPA?

Submitting CBI. Do not submit information containing CBI to 

the EPA through www.regulations.gov or email. Clearly mark 

the part or all of the information that you claim to be 

CBI. For CBI information on a disk or CD ROM that you mail 

to the EPA, mark the outside of the disk or CD ROM as CBI 

and then identify electronically within the disk or CD ROM 

the specific information that is claimed as CBI. In 

addition to one complete version of the comment that 

includes information claimed as CBI, a copy of the comment 

that does not contain the information claimed as CBI must 

be submitted for inclusion in the public docket. If you 
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submit a CD ROM or disk that does not contain CBI, mark the 

outside of the disk or CD ROM clearly that it does not 

contain CBI. Information not marked as CBI will be included 

in the public docket and the EPA’s electronic public docket 

without prior notice. Information marked as CBI will not be 

disclosed except in accordance with procedures set forth in 

40 CFR part 2. Send or deliver information identified as 

CBI only to the following address: Roberto Morales, OAQPS 

Document Control Officer (C404-02), Environmental 

Protection Agency, Office of Air Quality Planning and 

Standards, Research Triangle Park, North Carolina 27711, 

Attention Docket ID Number EPA-HQ-OAR-2010-0505.

D. When will a public hearing occur?

We will hold three public hearings, one in the Dallas, 

Texas area, one in Pittsburgh, Pennsylvania, and one in 

Denver, Colorado. If you are interested in attending or 

speaking at one of the public hearings, contact Ms. Joan 

Rogers at (919) 541-4487 by [INSERT DATE 11 DAYS FROM DATE 

OF PUBLICATION IN THE FEDERAL REGISTER]. Details on the 

public hearings will be provided in a separate notice and 

we will specify the time and date of the public hearings on 

http://www.epa.gov/airquality/oilandgas. If no one requests 

to speak at one of the public hearings [INSERT DATE 11 DAYS 
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FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER], then 

that public hearing will be cancelled without further 

notice. 

III. Background Information

A. What are standards of performance and NSPS?

1. What is the statutory authority for standards of 

performance and NSPS?

Section 111 of the Clean Air Act (CAA) requires the 

EPA Administrator to list categories of stationary sources,

if such sources cause or contribute significantly to air 

pollution, which may reasonably be anticipated to endanger 

public health or welfare. The EPA must then issue 

performance standards for such source categories. A

performance standard reflects the degree of emission 

limitation achievable through the application of the “best 

system of emission reduction” (BSER) which the EPA 

determines has been adequately demonstrated. The EPA may

consider certain costs and nonair quality health and 

environmental impact and energy requirements when 

establishing performance standards. Whereas CAA section 112 

standards are issued for existing and new stationary 

sources, standards of performance are issued for new and

modified stationary sources. These standards are referred 
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to as new source performance standards (NSPS). The EPA has 

the authority to define the source categories, determine 

the pollutants for which standards should be developed, 

identify the facilities within each source category to be 

covered and set the emission level of the standards. 

CAA section 111(b)(1)(B) requires the EPA to “at least 

every 8 years review and, if appropriate, revise” 

performance standards unless the “Administrator determines 

that such review is not appropriate in light of readily 

available information on the efficacy” of the standard. 

When conducting a review of an existing performance 

standard, the EPA has discretion to revise that standard to 

add emission limits for pollutants or emission sources not 

currently regulated for that source category.

In setting or revising a performance standard, CAA 

section 111(a)(1) provides that performance standards are 

to “reflect the degree of emission limitation achievable 

through the application of the best system of emission 

reduction which (taking into account the cost of achieving 

such reduction and any nonair quality health and 

environmental impact and energy requirements) the 

Administrator determines has been adequately demonstrated.” 

In this notice, we refer to this level of control as the 
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BSER. In determining BSER, we typically conduct a 

technology review that identifies what emission reduction 

systems exist and how much they reduce air pollution in 

practice. Next, for each control system identified, we 

evaluate its costs, secondary air benefits (or disbenefits) 

resulting from energy requirements and nonair quality 

impacts such as solid waste generation. Based on our 

evaluation, we would determine BSER. The resultant standard

is usually a numerical emissions limit, expressed as a 

performance level (i.e., a rate-based standard or percent 

control), that reflects the BSER. Although such standards 

are based on the BSER, the EPA may not prescribe a 

particular technology that must be used to comply with a

performance standard, except in instances where the 

Administrator determines it is not feasible to prescribe or 

enforce a standard of performance. Typically, sources 

remain free to elect whatever control measures that they 

choose to meet the emission limits. Upon promulgation, a 

NSPS becomes a national standard to which all new, modified

or reconstructed sources must comply.

2. What is the regulatory history regarding performance 

standards for the oil and natural gas sector?
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In 1979, the EPA listed crude oil and natural gas 

production on its priority list of source categories for 

promulgation of NSPS (44 FR 49222, August 21, 1979). On 

June 24, 1985 (50 FR 26122), the EPA promulgated a NSPS for 

the source category that addressed volatile organic 

compound (VOC) emissions from leaking components at onshore 

natural gas processing plants (40 CFR part 60, subpart 

KKK). On October 1, 1985 (50 FR 40158), a second NSPS was 

promulgated for the source category that regulates sulfur 

dioxide (SO2) emissions from natural gas processing plants 

(40 CFR part 60, subpart LLL). Other than natural gas 

processing plants, EPA has not previously set NSPS for a 

variety of oil and natural gas operations.

B. What are NESHAP?

1. What is the statutory authority for NESHAP?

Section 112 of the CAA establishes a two-stage 

regulatory process to address emissions of hazardous air 

pollutants (HAP) from stationary sources. In the first 

stage, after the EPA has identified categories of sources 

emitting one or more of the HAP listed in section 112(b) of 

the CAA, section 112(d) of the CAA calls for us to 

promulgate national emission standards for hazardous air 

pollutants (NESHAP) for those sources. “Major sources” are 
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those that emit or have the potential to emit (PTE) 10 tons 

per year (tpy) or more of a single HAP or 25 tpy or more of 

any combination of HAP. For major sources, these 

technology-based standards must reflect the maximum degree 

of emission reductions of HAP achievable (after considering 

cost, energy requirements and nonair quality health and 

environmental impacts) and are commonly referred to as 

maximum achievable control technology (MACT) standards.

MACT standards are to reflect application of measures, 

processes, methods, systems or techniques, including, but 

not limited to, measures which, (1) reduce the volume of or 

eliminate pollutants through process changes, substitution 

of materials or other modifications, (2) enclose systems or 

processes to eliminate emissions, (3) capture or treat 

pollutants when released from a process, stack, storage or 

fugitive emissions point, (4) are design, equipment, work 

practice or operational standards (including requirements 

for operator training or certification) or (5) are a 

combination of the above. CAA section 112(d)(2)(A)-(E). The 

MACT standard may take the form of a design, equipment, 

work practice or operational standard where the EPA first 

determines either that, (1) a pollutant cannot be emitted 

through a conveyance designed and constructed to emit or 
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capture the pollutant or that any requirement for or use of 

such a conveyance would be inconsistent with law or (2) the 

application of measurement methodology to a particular 

class of sources is not practicable due to technological 

and economic limitations. CAA sections 112(h)(1)-(2). 

The MACT “floor” is the minimum control level allowed 

for MACT standards promulgated under CAA section 112(d)(3), 

and may not be based on cost considerations. For new 

sources, the MACT floor cannot be less stringent than the 

emission control that is achieved in practice by the bestcontrolled similar source. The MACT floors for existing 

sources can be less stringent than floors for new sources, 

but they cannot be less stringent than the average emission 

limitation achieved by the best-performing 12 percent of 

existing sources in the category or subcategory (or the 

best-performing five sources for categories or 

subcategories with fewer than 30 sources). In developing 

MACT standards, we must also consider control options that 

are more stringent than the floor. We may establish 

standards more stringent than the floor based on the 

consideration of the cost of achieving the emissions 

reductions, any nonair quality health and environmental 

impacts and energy requirements.
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The EPA is then required to review these technologybased standards and to revise them “as necessary (taking 

into account developments in practices, processes, and 

control technologies)” no less frequently than every 8 

years, under CAA section 112(d)(6). In conducting this 

review, the EPA is not obliged to completely recalculate 

the prior MACT determination. NRDC v. EPA, 529 F.3d 1077, 

1084 (D.C. Cir. 2008). 

The second stage in standard-setting focuses on 

reducing any remaining “residual” risk according to CAA 

section 112(f). This provision requires, first, that the 

EPA prepare a Report to Congress discussing (among other 

things) methods of calculating risk posed (or potentially 

posed) by sources after implementation of the MACT 

standards, the public health significance of those risks, 

and the EPA’s recommendations as to legislation regarding 

such remaining risk. The EPA prepared and submitted this 

report (Residual Risk Report to Congress, EPA–453/R–99–001) 

in March 1999. Congress did not act in response to the 

report, thereby triggering the EPA’s obligation under CAA 

section 112(f)(2) to analyze and address residual risk.

CAA section 112(f)(2) requires us to determine for 

source categories subject to MACT standards, whether the 
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emissions standards provide an ample margin of safety to 

protect public health. If the MACT standards for HAP 

“classified as a known, probable, or possible human 

carcinogen do not reduce lifetime excess cancer risks to 

the individual most exposed to emissions from a source in 

the category or subcategory to less than 1-in-1 million,” 

the EPA must promulgate residual risk standards for the 

source category (or subcategory), as necessary, to provide 

an ample margin of safety to protect public health. In 

doing so, the EPA may adopt standards equal to existing 

MACT standards if the EPA determines that the existing 

standards are sufficiently protective. NRDC v. EPA, 529 

F.3d 1077, 1083 (D.C. Cir. 2008). (“If EPA determines that 

the existing technology-based standards provide an “ample 

margin of safety,” then the Agency is free to readopt those 

standards during the residual risk rulemaking.”) The EPA 

must also adopt more stringent standards, if necessary, to 

prevent an adverse environmental effect,1 but must consider 

cost, energy, safety and other relevant factors in doing 

so. 

 

1

“Adverse environmental effect” is defined in CAA section 

112(a)(7) as any significant and widespread adverse effect, which 

may be reasonably anticipated to wildlife, aquatic life or 

natural resources, including adverse impacts on populations of 

endangered or threatened species or significant degradation of 

environmental qualities over broad areas.
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Section 112(f)(2) of the CAA expressly preserves our 

use of a two-step process for developing standards to 

address any residual risk and our interpretation of “ample 

margin of safety” developed in the National Emission 

Standards for Hazardous Air Pollutants: Benzene Emissions 

from Maleic Anhydride Plants, Ethylbenzene/Styrene Plants, 

Benzene Storage Vessels, Benzene Equipment Leaks, and Coke 

By-Product Recovery Plants (Benzene NESHAP) (54 FR 38044, 

September 14, 1989). The first step in this process is the 

determination of acceptable risk. The second step provides 

for an ample margin of safety to protect public health, 

which is the level at which the standards are set (unless a 

more stringent standard is required to prevent, taking into 

consideration costs, energy, safety, and other relevant 

factors, an adverse environmental effect).

The terms “individual most exposed,” “acceptable 

level,” and “ample margin of safety” are not specifically 

defined in the CAA. However, CAA section 112(f)(2)(B) 

preserves the interpretation set out in the Benzene NESHAP, 

and the United States Court of Appeals for the District of 

Columbia Circuit in NRDC v. EPA, 529 F.3d 1077, concluded 

that the EPA’s interpretation of subsection 112(f)(2) is a 

reasonable one. See NRDC v. EPA, 529 F.3d at 1083 (D.C. 
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Cir., “[S]ubsection 112(f)(2)(B) expressly incorporates 

EPA’s interpretation of the Clean Air Act from the Benzene 

standard, complete with a citation to the Federal 

Register”). (D.C. Cir. 2008). See also, A Legislative 

History of the Clean Air Act Amendments of 1990, volume 1, 

p. 877 (Senate debate on Conference Report). We notified 

Congress in the Residual Risk Report to Congress that we 

intended to use the Benzene NESHAP approach in making CAA 

section 112(f) residual risk determinations (EPA–453/R–99–

001, p. ES–11).

In the Benzene NESHAP, we stated as an overall 

objective:

* * * in protecting public health with an ample margin 

of safety, we strive to provide maximum feasible 

protection against risks to health from hazardous air 

pollutants by, (1) protecting the greatest number of 

persons possible to an individual lifetime risk level 

no higher than approximately 1-in-1 million; and (2) 

limiting to no higher than approximately 1-in-10 

thousand [i.e., 100-in-1 million] the estimated risk 

that a person living near a facility would have if he 

or she were exposed to the maximum pollutant 

concentrations for 70 years. 
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The Agency also stated that, “The EPA also considers 

incidence (the number of persons estimated to suffer cancer 

or other serious health effects as a result of exposure to 

a pollutant) to be an important measure of the health risk 

to the exposed population. Incidence measures the extent of 

health risk to the exposed population as a whole, by 

providing an estimate of the occurrence of cancer or other 

serious health effects in the exposed population.” The 

Agency went on to conclude that “estimated incidence would 

be weighed along with other health risk information in 

judging acceptability.” As explained more fully in our 

Residual Risk Report to Congress, the EPA does not define 

“rigid line[s] of acceptability,” but considers rather 

broad objectives to be weighed with a series of other 

health measures and factors (EPA–453/R–99–001, p. ES–11). 

The determination of what represents an “acceptable” risk 

is based on a judgment of “what risks are acceptable in the 

world in which we live” (Residual Risk Report to Congress, 

p. 178, quoting the Vinyl Chloride decision at 824 F.2d 

1165) recognizing that our world is not risk-free.

In the Benzene NESHAP, we stated that “EPA will 

generally presume that if the risk to [the maximum exposed] 

individual is no higher than approximately 1-in-10 
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thousand, that risk level is considered acceptable.” 54 FR 

38045. We discussed the maximum individual lifetime cancer 

risk (or maximum individual risk (MIR)) as being “the 

estimated risk that a person living near a plant would have 

if he or she were exposed to the maximum pollutant 

concentrations for 70 years.” Id. We explained that this 

measure of risk “is an estimate of the upper bound of risk 

based on conservative assumptions, such as continuous 

exposure for 24 hours per day for 70 years.” Id. We 

acknowledge that maximum individual lifetime cancer risk 

“does not necessarily reflect the true risk, but displays a 

conservative risk level which is an upper-bound that is 

unlikely to be exceeded.” Id.

Understanding that there are both benefits and 

limitations to using maximum individual lifetime cancer 

risk as a metric for determining acceptability, we 

acknowledged in the 1989 Benzene NESHAP that “consideration 

of maximum individual risk * * * must take into account the 

strengths and weaknesses of this measure of risk.” Id.

Consequently, the presumptive risk level of 100-in-1 

million (1-in-10 thousand) provides a benchmark for judging 

the acceptability of maximum individual lifetime cancer 
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risk, but does not constitute a rigid line for making that 

determination. 

The Agency also explained in the 1989 Benzene NESHAP 

the following: “In establishing a presumption for MIR, 

rather than a rigid line for acceptability, the Agency 

intends to weigh it with a series of other health measures 

and factors. These include the overall incidence of cancer 

or other serious health effects within the exposed 

population, the numbers of persons exposed within each 

individual lifetime risk range and associated incidence 

within, typically, a 50-kilometer (km) exposure radius 

around facilities, the science policy assumptions and 

estimation uncertainties associated with the risk measures, 

weight of the scientific evidence for human health effects, 

other quantified or unquantified health effects, effects 

due to co-location of facilities and co-emission of 

pollutants.” Id.

In some cases, these health measures and factors taken 

together may provide a more realistic description of the 

magnitude of risk in the exposed population than that 

provided by maximum individual lifetime cancer risk alone. 

As explained in the Benzene NESHAP, “[e]ven though the 

risks judged “acceptable” by the EPA in the first step of 
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the Vinyl Chloride inquiry are already low, the second step 

of the inquiry, determining an “ample margin of safety,” 

again includes consideration of all of the health factors, 

and whether to reduce the risks even further.” In the ample 

margin of safety decision process, the Agency again 

considers all of the health risks and other health 

information considered in the first step. Beyond that 

information, additional factors relating to the appropriate 

level of control will also be considered, including costs 

and economic impacts of controls, technological 

feasibility, uncertainties and any other relevant factors. 

Considering all of these factors, the Agency will establish 

the standard at a level that provides an ample margin of 

safety to protect the public health, as required by CAA 

section 112(f). 54 FR 38046.

2. How do we consider the risk results in making decisions?

As discussed in the previous section of this preamble, 

we apply a two-step process for developing standards to 

address residual risk. In the first step, the EPA 

determines if risks are acceptable. This determination 

“considers all health information, including risk 

estimation uncertainty, and includes a presumptive limit on 
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maximum individual lifetime [cancer] risk (MIR)2 of 

approximately 1-in-10 thousand [i.e., 100-in-1 million].” 

54 FR 38045. In the second step of the process, the EPA 

sets the standard at a level that provides an ample margin 

of safety “in consideration of all health information, 

including the number of persons at risk levels higher than 

approximately 1-in-1 million, as well as other relevant 

factors, including costs and economic impacts, 

technological feasibility, and other factors relevant to 

each particular decision.” Id. 

In past residual risk determinations, the EPA 

presented a number of human health risk metrics associated 

with emissions from the category under review, including: 

The MIR; the numbers of persons in various risk ranges; 

cancer incidence; the maximum noncancer hazard index (HI); 

and the maximum acute noncancer hazard. In estimating 

risks, the EPA considered source categories under review 

that are located near each other and that affect the same 

population. The EPA provided estimates of the expected 

difference in actual emissions from the source category 

under review and emissions allowed pursuant to the source 

 

2

Although defined as “maximum individual risk,” MIR refers only 

to cancer risk. MIR, one metric for assessing cancer risk, is the 

estimated risk were an individual exposed to the maximum level of 

a pollutant for a lifetime.
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category MACT standard. The EPA also discussed and 

considered risk estimation uncertainties. The EPA is 

providing this same type of information in support of these 

actions.

The Agency acknowledges that the Benzene NESHAP 

provides flexibility regarding what factors the EPA might 

consider in making our determinations and how they might be 

weighed for each source category. In responding to comment 

on our policy under the Benzene NESHAP, the EPA explained 

that: “The policy chosen by the Administrator permits 

consideration of multiple measures of health risk. Not only 

can the MIR figure be considered, but also incidence, the 

presence of noncancer health effects, and the uncertainties 

of the risk estimates. In this way, the effect on the most 

exposed individuals can be reviewed as well as the impact 

on the general public. These factors can then be weighed in 

each individual case. This approach complies with the Vinyl 

Chloride mandate that the Administrator ascertain an 

acceptable level of risk to the public by employing [her] 

expertise to assess available data. It also complies with 

the Congressional intent behind the CAA, which did not 

exclude the use of any particular measure of public health 

risk from the EPA's consideration with respect to CAA 
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section 112 regulations, and, thereby, implicitly permits 

consideration of any and all measures of health risk which 

the Administrator, in [her] judgment, believes are 

appropriate to determining what will ‘protect the public 

health.’”

For example, the level of the MIR is only one factor 

to be weighed in determining acceptability of risks. The 

Benzene NESHAP explains “an MIR of approximately 1-in-10 

thousand should ordinarily be the upper end of the range of

acceptability. As risks increase above this benchmark, they 

become presumptively less acceptable under CAA section 112, 

and would be weighed with the other health risk measures 

and information in making an overall judgment on 

acceptability. Or, the Agency may find, in a particular 

case, that a risk that includes MIR less than the 

presumptively acceptable level is unacceptable in the light 

of other health risk factors.” Similarly, with regard to 

the ample margin of safety analysis, the Benzene NESHAP 

states that: “EPA believes the relative weight of the many 

factors that can be considered in selecting an ample margin 

of safety can only be determined for each specific source 

category. This occurs mainly because technological and 
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economic factors (along with the health-related factors) 

vary from source category to source category.” 

3. What is the regulatory history regarding NESHAP for the 

oil and natural gas sector?

On July 16, 1992 (57 FR 31576), the EPA published a 

list of major and area sources for which NESHAP are to be 

published (i.e., the source category list). Oil and natural 

gas production facilities were listed as a category of 

major sources. On February 12, 1998 (63 FR 7155), the EPA 

amended the source category list to add Natural Gas 

Transmission and Storage as a major source category.

On June 17, 1999 (64 FR 32610), the EPA promulgated 

MACT standards for the Oil and Natural Gas Production and 

Natural Gas Transmission and Storage major source 

categories. The Oil and Natural Gas Production NESHAP (40 

CFR part 63, subpart HH) contains standards for HAP 

emissions from glycol dehydration process vents, storage 

vessels and natural gas processing plant equipment leaks. 

The Natural Gas Transmission and Storage NESHAP (40 CFR 

part 63, subpart HHH) contains standards for glycol 

dehydration process vents.

In addition to these NESHAP for major sources, the EPA 

also promulgated NESHAP for the Oil and Natural Gas 
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Production area source category on January 3, 2007 (72 FR 

26). These area source standards, which are based on 

generally available control technology, are also contained 

in 40 CFR part 63, subpart HH. This proposed action does 

not impact these area source standards.

C. What litigation is related to this proposed action?

On January 14, 2009, pursuant to section 304(a)(2) of 

the CAA, WildEarth Guardians and the San Juan Citizens 

Alliance filed a Complaint alleging that the EPA failed to 

meet its obligations under CAA sections 111(b)(1)(B), 

112(d)(6) and 112(f)(2) to take actions relative to the 

review/revision of the NSPS and the NESHAP with respect to 

the Oil and Natural Gas Production source category. On 

February 4, 2010, the Court entered a consent decree 

requiring the EPA to sign by July 28, 2011,

3 proposed 

standards and/or determinations not to issue standards 

pursuant to CAA sections 111(b)(1)(B), 112(d)(6) and 

112(f)(2) and to take final action by February 28, 2012. 

D. What is a sector-based approach?

 

3

On April 27, 2011, pursuant to paragraph 10(a) of the Consent 

Decree, the parties filed with the Court a written stipulation 

that changes the proposal date from January 31, 2011, to July 28, 

2011, and the final action date from November 30, 2011, to 

February 28, 2012. 
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Sector-based approaches are based on integrated 

assessments that consider multiple pollutants in a 

comprehensive and coordinated manner to manage emissions 

and CAA requirements. One of the many ways we can address 

sector-based approaches is by reviewing multiple regulatory 

programs together whenever possible, consistent with all 

applicable legal requirements. This approach essentially 

expands the technical analyses on costs and benefits of 

particular technologies, to consider the interactions of 

rules that regulate sources. The benefit of multi-pollutant 

and sector-based analyses and approaches includes the 

ability to identify optimum strategies, considering 

feasibility, cost impacts and benefits across the different 

pollutant types while streamlining administrative and 

compliance complexities and reducing conflicting and 

redundant requirements, resulting in added certainty and 

easier implementation of control strategies for the sector 

under consideration. In order to benefit from a sectorbased approach for the oil and gas industry, the EPA 

analyzed how the NSPS and NESHAP under consideration relate 

to each other and other regulatory requirements currently 

under review for oil and gas facilities. In this analysis,

we looked at how the different control requirements that 
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result from these requirements interact, including the 

different regulatory deadlines and control equipment 

requirements that result, the different reporting and 

recordkeeping requirements and opportunities for states to 

account for reductions resulting from this rulemaking in 

their State Implementation Plans (SIP). The requirements 

analyzed affect criteria pollutant, HAP and methane

emissions from oil and natural gas processes and cover the 

NSPS and NESHAP reviews. As a result of the sector-based 

approach, this rulemaking will reduce conflicting and 

redundant requirements. Also, the sector-based approach 

facilitated the streamlining of monitoring, recordkeeping 

and reporting requirements, thus, reducing administrative 

and compliance complexities associated with complying with 

multiple regulations. In addition, the sector-based 

approach promotes a comprehensive control strategy that 

maximizes the co-control of multiple regulated pollutants 

while obtaining emission reductions as co-benefits.

IV. Oil and Natural Gas Sector

The oil and natural gas sector includes operations 

involved in the extraction and production of oil and 

natural gas, as well as the processing, transmission and 

distribution of natural gas. Specifically for oil, the 
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sector includes all operations from the well to the point 

of custody transfer at a petroleum refinery. For natural 

gas, the sector includes all operations from the well to 

the customer. The oil and natural gas operations can 

generally be separated into four segments: (1) Oil and 

natural gas production, (2) natural gas processing, (3) 

natural gas transmission and (4) natural gas distribution. 

Each of these segments is briefly discussed below. 

Oil and natural gas production includes both onshore 

and offshore operations. Production operations include the 

wells and all related processes used in the extraction, 

production, recovery, lifting, stabilization, separation or 

treating of oil and/or natural gas (including condensate). 

Production components may include, but are not limited to, 

wells and related casing head, tubing head and “Christmas 

tree” piping, as well as pumps, compressors, heater 

treaters, separators, storage vessels, pneumatic devices

and dehydrators. Production operations also include the 

well drilling, completion and workover processes and 

includes all the portable non-self-propelled apparatus

associated with those operations. Production sites include 

not only the “pads” where the wells are located, but also 

include stand-alone sites where oil, condensate, produced 
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water and gas from several wells may be separated, stored

and treated. The production sector also includes the low 

pressure, small diameter, gathering pipelines and related 

components that collect and transport the oil, gas and 

other materials and wastes from the wells to the refineries 

or natural gas processing plants. None of the operations 

upstream of the natural gas processing plant are covered by 

the existing NSPS. Offshore oil and natural gas production 

occurs on platform structures that house equipment to 

extract oil and gas from the ocean or lake floor and that 

process and/or transfer the oil and gas to storage, 

transport vessels or onshore. Offshore production can also 

include secondary platform structures connected to the 

platform structure, storage tanks associated with the 

platform structure and floating production and offloading 

equipment.

There are three basic types of wells: Oil wells, gas 

wells and associated gas wells. Oil wells can have 

“associated” natural gas that is separated and processed or 

the crude oil can be the only product processed. Once the 

crude oil is separated from the water and other impurities, 

it is essentially ready to be transported to the refinery 

via truck, railcar or pipeline. We consider the oil 
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refinery sector separately from the oil and natural gas 

sector. Therefore, at the point of custody transfer at the 

refinery, the oil leaves the oil and natural gas sector and 

enters the petroleum refining sector.

Natural gas is primarily made up of methane. However, 

whether natural gas is associated gas from oil wells or 

non-associated gas from gas or condensate wells, it 

commonly exists in mixtures with other hydrocarbons. These 

hydrocarbons are often referred to as natural gas liquids 

(NGL). They are sold separately and have a variety of 

different uses. The raw natural gas often contains water 

vapor, hydrogen sulfide (H2S), carbon dioxide (CO2), 

helium, nitrogen and other compounds. Natural gas 

processing consists of separating certain hydrocarbons and 

fluids from the natural gas to produced “pipeline quality” 

dry natural gas. While some of the processing can be 

accomplished in the production segment, the complete 

processing of natural gas takes place in the natural gas 

processing segment. Natural gas processing operations 

separate and recover NGL or other non-methane gases and 

liquids from a stream of produced natural gas through 

components performing one or more of the following 

processes: Oil and condensate separation, water removal, 
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separation of NGL, sulfur and CO2 removal, fractionation of 

natural gas liquid and other processes, such as the capture 

of CO2 separated from natural gas streams for delivery 

outside the facility. Natural gas processing plants are the 

only operations covered by the existing NSPS.

The pipeline quality natural gas leaves the processing 

segment and enters the transmission segment. Pipelines in 

the natural gas transmission segment can be interstate 

pipelines that carry natural gas across state boundaries or 

intrastate pipelines, which transport the gas within a 

single state. While interstate pipelines may be of a larger 

diameter and operated at a higher pressure, the basic 

components are the same. To ensure that the natural gas 

flowing through any pipeline remains pressurized, 

compression of the gas is required periodically along the 

pipeline. This is accomplished by compressor stations 

usually placed between 40 and 100 mile intervals along the 

pipeline. At a compressor station, the natural gas enters 

the station, where it is compressed by reciprocating or 

centrifugal compressors.

In addition to the pipelines and compressor stations, 

the natural gas transmission segment includes underground 

storage facilities. Underground natural gas storage 
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includes subsurface storage, which typically consists of 

depleted gas or oil reservoirs and salt dome caverns used

for storing natural gas. One purpose of this storage is for 

load balancing (equalizing the receipt and delivery of 

natural gas). At an underground storage site, there are 

typically other processes, including compression, 

dehydration and flow measurement.

The distribution segment is the final step in 

delivering natural gas to customers. The natural gas enters 

the distribution segment from delivery points located on 

interstate and intrastate transmission pipelines to 

business and household customers. The delivery point where 

the natural gas leaves the transmission segment and enters 

the distribution segment is often called the “citygate.” 

Typically, utilities take ownership of the gas at the 

citygate. Natural gas distribution systems consist of 

thousands of miles of piping, including mains and service 

pipelines to the customers. Distribution systems sometimes 

have compressor stations, although they are considerably 

smaller than transmission compressor stations. Distribution 

systems include metering stations, which allow distribution 

companies to monitor the natural gas in the system. 

Essentially, these metering stations measure the flow of 
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gas and allow distribution companies to track natural gas 

as it flows through the system.

Emissions can occur from a variety of processes and 

points throughout the oil and natural gas sector. 

Primarily, these emissions are organic compounds such as 

methane, ethane, VOC and organic HAP. The most common 

organic HAP are n-hexane and BTEX compounds (benzene, 

toluene, ethylbenzene and xylenes). Hydrogen sulfide (H2S)

and sulfur dioxide (SO2) are emitted from production and 

processing operations that handle and treat “sour gas.”

Sour gas is defined as natural gas with a maximum H2S 

content of 0.25 gr/100 scf (4ppmv) along with the presence 

of CO2.

In addition, there are significant emissions 

associated with the reciprocating internal combustion 

engines and combustion turbines that power compressors 

throughout the oil and natural gas sector. However, 

emissions from internal combustion engines and combustion 

turbines are covered by regulations specific to engines and 

turbines and, thus, are not addressed in this action.

V. Summary of Proposed Decisions and Actions

Pursuant to CAA sections 111(b), 112(d)(2), 112(d)(6)

and 112(f), we are proposing to revise the NSPS and NESHAP 
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relative to oil and gas to include the standards and 

requirements summarized in this section. More details of 

the rationale for these proposed standards and requirements 

are provided in sections VI and VII of this preamble. In 

addition, as part of these rationale discussions, we 

solicit public comment and data relevant to several issues. 

The comments we receive during the public comment period 

will help inform the rule development process as we work 

toward promulgating a final action. 

A. What are the proposed revisions to the NSPS?

We reviewed the two NSPS that apply to the oil and 

natural gas industry. Based on our review, we believe that 

the requirements at 40 CFR part 60, subpart KKK, should be 

updated to reflect requirements in 40 CFR part 60, subpart 

VVa for controlling VOC equipment leaks at processing 

plants. We also believe that the requirements at 40 CFR 

part 60, subpart LLL, for controlling SO2 emissions from 

natural gas processing plants should be strengthened for 

facilities with the highest sulfur feed rates and the 

highest H2S concentrations. For a more detailed discussion, 

please see section VI.B.1 of this preamble.

In addition, there are significant VOC emissions from 

oil and natural gas operations that are not covered by the 
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two existing NSPS, including other emissions at processing 

plants and emissions from upstream production, as well as 

transmission and storage facilities. In the 1984 notice 

that listed source categories (including Oil and Natural 

Gas) for promulgation of NSPS, we noted that there were 

discrepancies between the source category names on the list 

and those in the background document, and we clarified our 

intent to address all sources under an industry heading at 

the same time. See 44 FR 49222, 49224-49225.4 We, therefore,

believe that the currently listed Oil and Natural Gas

source category covers all operations in this industry

(i.e., production, processing, transmission, storage and 

distribution). To the extent there are oil and gas 

operations not covered by the currently listed Oil and 

Natural Gas source category, pursuant to CAA section 

111(b), we hereby modify the category list to include all 

operations in the oil and natural gas sector. Section 

111(b) of the CAA gives the EPA broad authority and 

discretion to list and establish NSPS for a category that, 

in the Administrator’s judgment, causes or contributes 

significantly to air pollution which may reasonably be 

 

4

The Notice further states that “The Administrator may also 

concurrently develop standards for sources which are not on the 

priority list.” 44 FR at 49225. 
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anticipated to endanger public health or welfare. Pursuant 

to CAA section 111(b), we are modifying the source category 

list to include any oil and gas operation not covered by 

the current listing and evaluating emissions from all oil 

and gas operations at the same time.

We are also proposing standards for several new oil 

and natural gas affected facilities. The proposed standards 

would apply to affected facilities that commence 

construction, reconstruction or modification after [INSERT 

DATE OF PUBLICATION IN THE FEDERAL REGISTER]. These 

standards, which include requirements for VOC, would be 

contained in a new subpart, 40 CFR part 60, subpart OOOO. 

Subpart OOOO would incorporate 40 CFR part 60, subpart KKK 

and 40 CFR part 60, subpart LLL, thereby having in this one 

subpart, all standards that are applicable to the new and 

modified affected facilities described above. We also 

propose to amend the title of subparts KKK and LLL, 

accordingly, to apply only to affected facilities already 

subject to those subparts. Those operations would not

become subject to subpart OOOO unless they triggered 

applicability based on new or modified affected facilities 

under subpart OOOO. 
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We are proposing operational standards for completions 

of hydraulically fractured gas wells. Based on our review, 

we identified two subcategories of fractured gas wells for 

which well completions are conducted. For non-exploratory 

and non-delineation wells, the proposed operational 

standards would require reduced emission completion (REC), 

commonly referred to as “green completion,” in combination 

with pit-flaring of gas not suitable for entering the 

gathering line. For exploratory and delineation wells 

(these wells generally are not in close proximity to a 

gathering line), we proposed an operational standard that 

would require pit flaring. Well completions subject to the 

standards would be limited to gas well completions 

following hydraulic fracturing operations. These 

completions include those conducted at newly drilled and 

fractured wells, as well as completions conducted following 

refracturing operations at various times over the life of 

the well. We have determined that a completion associated 

with refracturing performed at an existing well (i.e., a 

well existing prior to (INSERT DATE OF PUBLICATION IN THE 

FEDERAL REGISTER)) is considered a modification under CAA 

section 111(a), because physical change occurs to the 

existing well resulting in emissions increase during the 
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refracturing and completion operation. A detailed 

discussion of this determination is presented in the 

Technical Support Document (TSD) in the docket. Therefore, 

the proposed standards would apply to completions at new 

gas wells that are fractured or refractured along with 

completions associated with fracturing or refracturing of 

existing gas wells. The modification determination and 

resultant applicability of NSPS to the completion operation 

following fracturing or refracturing of existing gas wells 

(i.e., wells existing before [INSERT DATE OF PUBLICATION IN 

THE FEDERAL REGISTER] would be limited strictly to the 

wellhead, well bore, casing and tubing, and any conveyance 

through which gas is vented to the atmosphere and not be 

extended beyond the wellhead to other ancillary components 

that may be at the well site such as existing storage 

vessels, process vessels, separators, dehydrators or any 

other components or apparatus. 

We are also proposing VOC standards to reduce 

emissions from gas-driven pneumatic devices. We are 

proposing that each pneumatic device is an affected 

facility. Accordingly, the proposed standards would apply 

to each newly installed pneumatic device (including 

replacement of an existing device). At gas processing 
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plants, we are proposing a zero emission limit for each 

individual pneumatic controller. The proposed emission 

standards would reflect the emission level achievable from 

the use of non-gas-driven pneumatic controllers. At other 

locations, we are proposing a bleed limit of 6 standard 

cubic feet of gas per hour for an individual pneumatic 

controller, which would reflect the emission level 

achievable from the use of low bleed gas-driven pneumatic 

controllers. In both cases, the standards provide 

exemptions for certain applications based on functional 

considerations.

In addition, the proposed rule would require measures 

to reduce VOC emissions from centrifugal and reciprocating 

compressors. As explained in more detail below in section 

VI.B.4, we are proposing equipment standards for 

centrifugal compressors. The proposed standards would 

require the use of dry seal systems. However, we are aware 

that some owners and operators may need to use centrifugal 

compressors with wet seals, and we are soliciting comment 

on the suitability of a compliance option allowing the use 

of wet seals combined with routing of emissions from the 

seal liquid through a closed vent system to a control 
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device as an acceptable alternative to installing dry 

seals. 

Our review of reciprocating compressors found that 

piston rod packing wear produces fugitive emissions that 

cannot be captured and conveyed to a control device. As a 

result, we are proposing operational standards for 

reciprocating compressors, such that the proposed rule 

would require replacement of the rod packing based on hours 

of usage. The owner or operator of a reciprocating 

compressor affected facility would be required to monitor 

the duration (in hours) that the compressor is operated. 

When the hours of operation reaches 26,000 hours, the owner 

or operator would be required to change the rod packing 

immediately. However, to avoid unscheduled shutdowns when 

26,000 hours is reached, owners and operators could track 

hours of operation such that packing replacement could be 

coordinated with planned maintenance shutdowns before hours 

of operation reached 26,000. Some operators may prefer to 

replace the rod packing on a fixed schedule to ensure that 

the hours of operation would not reach 26,000 hours. We 

solicit comment on the appropriateness of a fixed 

replacement frequency and other considerations that would 

be associated with regular replacement.
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We are also proposing VOC standards for new or 

modified storage vessels. The proposed rule, which would 

apply to individual vessels, would require that vessels 

meeting certain specifications achieve at least 95-percent 

reduction in VOC emissions. Requirements would apply to 

vessels with a throughput of 1 barrel of condensate per day 

or 20 barrels of crude oil per day. These thresholds are 

equivalent to VOC emissions of about 6 tpy. 

For gas processing plants, we are updating the 

requirements for leak detection and repair (LDAR) to 

reflect procedures and leak thresholds established by 40 

CFR 60, subpart VVa. The existing NSPS requires 40 CFR part 

60, subpart VV procedures and thresholds.

For 40 CFR part 60, subpart LLL, which regulates SO2

emissions from natural gas processing plants, we determined 

that affected facilities with sulfur feed rate of at least 

5 long tons per day or H2S concentration in the acid gas 

stream of at least 50 percent can achieve up to 99.9-

percent SO2 control, which is greater than the existing 

standard. Therefore, we are proposing revision to the 

performance standards in subpart LLL as a result of this 

review. For a more detailed discussion of this proposed 

determination, please see section VI.B.1 of this preamble. 
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We are proposing to address compliance requirements 

for periods of startup, shutdown and malfunction (SSM) for 

40 CFR part 60, subpart OOOO. The SSM changes are discussed 

in detail in section VI.B.5 below. In addition, we are 

proposing to incorporate the requirements in 40 CFR part 

60, subpart KKK and 40 CFR part 60, subpart LLL into the 

new subpart OOOO so that all requirements applicable to the 

new and modified facilities would be in one subpart. This 

would simplify and streamline compliance efforts on the 

part of the oil and natural gas industry and could minimize 

duplication of notification, recordkeeping and reporting.

B. What are the proposed decisions and actions related to 

the NESHAP?

This section summarizes the results of our RTR for the 

Oil and Natural Gas Production and the Natural Gas 

Transmission and Storage source categories and our proposed 

decisions concerning these two 1999 NESHAP.

1. Addressing Unregulated Emissions Sources 

Pursuant to CAA sections 112(d)(2) and (3), we are 

proposing MACT standards for subcategories of glycol 

dehydrators for which standards were not previously 

developed (hereinafter referred to as the “small 

dehydrators”). In the Oil and Natural Gas Production source 
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category, the subcategory consists of glycol dehydrators 

with an actual annual average natural gas flowrate less 

than 85,000 standard cubic meters per day (scmd) or actual 

average benzene emissions less than 0.9 megagrams per year 

(Mg/yr). In the Natural Gas Transmission and Storage source 

category, the subcategory consists of glycol dehydrators 

with an actual annual average natural gas flowrate less 

than 283,000 scmd or actual average benzene emissions less 

than 0.9 Mg/yr.

The proposed MACT standards for the subcategory of 

small dehydrators at oil and gas production facilities 

would require that existing affected sources meet a unitspecific BTEX limit of 1.10x10-4 grams BTEX/standard cubic 

meters (scm)-parts per million by volume (ppmv) and that 

new affected sources meet a BTEX limit of 4.66 x10-6 grams 

BTEX/scm-ppmv. At natural gas transmission and storage 

affected sources, the proposed MACT standard for the 

subcategory of small dehydrators would require that 

existing affected sources meet a unit-specific BTEX 

emission limit of 6.42x10-5 grams BTEX/scm-ppmv and that new 

affected sources meet a BTEX limit of 1.10 x10-5 grams 

BTEX/scm-ppmv.

We are also proposing MACT standards for storage 
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vessels that are currently not regulated under the Oil and 

Natural Gas Production NESHAP. The current MACT standards 

apply only to storage vessels with the potential for flash 

emissions (PFE). As explained in section VII, the original 

MACT analysis accounted for all storage vessels. We are,

therefore, proposing to apply the current MACT standards of 

95-percent emission reduction to every storage vessel at 

major source oil and natural gas production facilities. In 

conjunction with this change, we are proposing to amend the 

definition of associated equipment to exclude all storage 

vessels, and not just those with the PFE, from being 

considered “associated equipment.” This means that 

emissions from all storage vessels, and not just those from 

storage vessels with the PFE, are to be included in the 

major source determination.

2. What are the proposed decisions and actions related to 

the risk review?

For both the Oil and Natural Gas Production and the 

Natural Gas Transmission and Storage source categories, we 

find that the current levels of emissions allowed by the 

MACT reflect acceptable levels of risk; however, the level 

of emissions allowed by the alternative compliance option 

for glycol dehydrator MACT (i.e., the option of reducing 
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benzene emissions to less than 0.9 Mg/yr in lieu of the 

MACT standard of 95-percent control) reflects an 

unacceptable level of risk. We are, therefore, proposing to 

eliminate the 0.9 Mg/yr alternative compliance option.

In addition, we are proposing that the MACT for these 

two oil and gas source categories, as revised per above, 

provide an ample margin of safety to protect public health 

and prevent adverse environmental effects.

3. What are the proposed decisions and actions related to 

the technology reviews of the existing NESHAP?

For both the Oil and Natural Gas Production and the 

Natural Gas Transmission and Storage source categories, we 

are proposing no revisions to the existing NESHAP pursuant 

to section 112(d)(6) of the CAA. 

4. What other actions are we proposing?

We are proposing an alternative performance test for 

non-flare, combustion control devices. This test is to be 

conducted by the combustion control device manufacturer to 

demonstrate the destruction efficiency achieved by a 

specific model of combustion control device. This would 

allow a source to purchase a performance tested device for 

installation at their site without being required to 

conduct a site-specific performance test. A definition for 
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“flare” is being proposed in the NESHAP to clarify which 

combustion control devices fall under the manufacturers’ 

performance testing alternative, and to clarify which 

devices must be performance tested.

We are also proposing to: Revise the parametric 

monitoring calibration provisions; require periodic 

performance testing where applicable; remove the allowance 

of a design analysis for all control devices other than 

condensers; remove the requirement for a minimum residence 

time for an enclosed combustion device; and add 

recordkeeping and reporting requirements to document carbon 

replacement intervals. These changes are being proposed to 

bring the NESHAP up-to-date based on what we have learned 

regarding control devices and compliance since the original 

promulgation date. 

In addition, we are proposing the elimination of the 

SSM exemption in the Oil and Natural Gas Production and the 

Natural Gas Transmission and Storage NESHAP. As discussed 

in more detail below in section VII, consistent with Sierra 

Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2010), the EPA is 

proposing that the established standards in these two 

NESHAP apply at all times. We are proposing to revise Table 

2 to both 40 CFR part 63, subpart HH and 40 CFR part 63, 
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subpart HHH to indicate that certain 40 CFR part 63 general 

provisions relative to SSM do not apply, including: 40 CFR 

63.6 (e)(1)(i)5 and (ii), 40 CFR 63.6(e)(3) (SSM plan 

requirement), 40 CFR 63.6(f)(1); 40 CFR 63.7(e)(1), 40 CFR 

63.8(c)(1)(i) and (iii), and the last sentence of 40 CFR 

63.8(d)(3); 40 CFR 63.10(b)(2)(i),(ii), (iv) and (v); 40 

CFR 63.10(c)(10), (11) and (15); and 40 CFR 63.10(d)(5). We 

are also proposing to: (1) Revise 40 CFR 63.771(d)(4)(i) 

and 40 CFR 63.1281(d)(4)(i) regarding operation of the 

control device to be consistent with the SSM compliance 

requirements; and (2) revise the SSM-associated reporting 

and recordkeeping requirements in 40 CFR 63.774, 40 CFR 

63.775, 40 CFR 63.1284 and 40 CFR 63.1285 to require 

reporting and recordkeeping for periods of malfunction. In 

addition, as explained below, we are proposing to add an 

affirmative defense to civil penalties for exceedances of 

emission limits caused by malfunctions, as well as criteria 

for establishing the affirmative defense. 

The EPA has attempted to ensure that we have neither 

overlooked nor failed to propose to remove from the 

 

5

40 CFR 63.6(e)(1)(i) requires owners or operators to act 

according to the general duty to “operate and maintain any 

affected source, including associated air pollution control 

equipment and monitoring equipment, in a manner consistent with 

safety and good air pollution control practices for minimizing 

emissions.” This general duty to minimize is included in our 

proposed standard at 40 CFR 63.783(b)(1).
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existing text any provisions that are inappropriate, 

unnecessary or redundant in the absence of the SSM 

exemption, nor included any such provisions in the proposed 

new regulatory language. We are specifically seeking 

comment on whether there are any such provisions that we 

have inadvertently overlooked or incorporated.

We are also revising the applicability provisions of 

40 CFR part 63, subpart HH to clarify requirements 

regarding PTE determination and the scope of a facility 

subject to subpart HH. Lastly, we are proposing several 

editorial corrections and plain language revisions to 

improve these rules. 

C. What are the proposed notification, recordkeeping and 

reporting requirements for this proposed action?

1. What are the proposed notification, recordkeeping and 

reporting requirements for the proposed NSPS?

The proposed 40 CFR part 60, subpart OOOO includes new 

requirements for several operations for which there are no 

existing Federal standards. Most notably, as discussed in 

sections V.A and VI.B of this preamble, the proposed NSPS 

will cover completions and recompletions of hydraulically 

fractured gas wells. We estimate that over 20,000 

completions and recompletions annually will be subject to 
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the proposed requirements. Given the number of these 

operations, we believe that notification and reporting must 

be streamlined to the extent possible to minimize undue 

burden on owners and operators, as well as state, local and 

tribal agencies. In section V.D of this preamble, we 

discuss some innovative implementation approaches being 

considered and seek comment on these and other potential 

methods of streamlining notification and reporting for well 

completions covered by the proposed rule.

Owners or operators are required to submit initial

notifications and annual reports, and to retain records to 

assist in documenting that they are complying with the 

provisions of the NSPS. These notification, recordkeeping

and reporting activities include both requirements of the 

40 CFR part 60 General Provisions, as well as requirements 

specific to 40 CFR part 60, subpart OOOO. 

Owners or operators of affected facilities (except for 

pneumatic controller and gas wellhead affected sources) 

must submit an initial notification within 1 year after 

becoming subject to 40 CFR part 60, subpart OOOO or by 1 

year after the publication of the final rule in the Federal 

Register, whichever is later. For pneumatic controllers, 

owners and operators are not required to submit an initial 
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notification, but instead are required to report the 

installation of these affected facilities in their 

facility’s annual report. Owners or operators of wellhead 

affected facilities (well completions) would also be 

required to submit a 30-day advance notification of each 

well completion subject to the NSPS. In addition, annual 

reports are due 1 year after initial startup date for your 

affected facility or 1 year after the date of publication 

of the final rule in the Federal Register, whichever is 

later. The notification and annual reports must include 

information on all affected facilities owned or operated 

that were new, modified or reconstructed sources during the 

reporting period. A single report may be submitted covering 

multiple affected facilities, provided that the report 

contains all the information required by 40 CFR 60.5420(b). 

This information includes general information on the 

facility (i.e., company name and address, etc.), as well as 

information specific to individual affected facilities. 

For wellhead affected facilities, this information 

includes details of each well completion during the period, 

including duration of periods of gas recovery, flaring and 

venting. For centrifugal compressor affected facilities, 

information includes documentation that the compressor is 
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fitted with dry seals. For reciprocating compressors, 

information includes the cumulative hours of operation of 

each compressor and records of rod packing replacement. 

Information for pneumatic device affected facilities 

includes location and manufacturer specifications of each 

pneumatic controller installed during the period and

documentation that supports any exemption claimed allowing 

use of high bleed controllers. For controllers installed at 

gas processing plants, the owner or operator would document 

the use of non-gas driven devices. For controllers 

installed in locations other than at gas processing plants, 

owners or operators would provide manufacturer’s 

specifications that document bleed rate not exceeding 6 

cubic feet per hour.

For storage vessel affected facilities, required 

report information includes information that documents 

control device compliance, if applicable. For vessels with 

throughputs below 1 barrel of condensate per day and 21 

barrels of crude oil per day, required information also 

includes calculations or other documentation of the 

throughput. For onshore gas processing plants, semi-annual 

reports are required, and include information on number of 

pressure relief devices, number of pressure relief devices 
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for which leaks were detected and pressure relief devices 

for which leaks were not repaired, as required in 40 CFR

60.5396 of subpart OOOO.

Records must be retained for 5 years and generally 

consist of the same information required in the initial 

notification and annual and semiannual reports. 

2. What are the proposed amendments to notification, 

recordkeeping and reporting requirements for the NESHAP?

We are proposing to revise certain recordkeeping 

requirements of 40 CFR part 63, subpart HH and 40 CFR part 

63, subpart HHH. Specifically, we are proposing that 

facilities using carbon adsorbers as a control device keep 

records of their carbon replacement schedule and records 

for each carbon replacement. In addition, owners and 

operators are required to keep records of the occurrence 

and duration of each malfunction or operation of the air 

pollution control equipment and monitoring equipment.

In addition, in conjunction with the proposed MACT 

standards for small glycol dehydration units and storage 

vessels that do not have the PFE in the proposed amendment 

to 40 CFR part 63, subpart HH, we are proposing that owners 

and operators of affected small glycol dehydration units 

and storage vessels submit an initial notification within 1 
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year after becoming subject to subpart HH or by 1 year 

after the publication of the final rule in the Federal 

Register, whichever is later. 

Similarly, in conjunction with the proposed MACT 

standards for small glycol dehydration units in the 

proposed 40 CFR part 63, subpart HHH amendments, we are 

proposing that owners and operators of small glycol 

dehydration units submit an initial notification within 1 

year after becoming subject to subpart HHH or by 1 year 

after the publication of the final rule in the Federal 

Register, whichever is later. Affected sources under either 

40 CFR part 63, subpart HH or subpart HHH that plan to be 

area sources by the compliance dates will be required to 

submit a notification describing their schedule for the 

actions planned to achieve area source status.

The proposed amendments to the NESHAP also include 

additional requirements for the contents of the periodic 

reports. For both 40 CFR part 63, subpart HH and 40 CFR 

part 63, subpart HHH, we are proposing that the periodic 

reports also include periodic test results and information 

regarding any carbon replacement events that occurred

during the reporting period.
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3. How is information submitted using the Electronic 

Reporting Tool (ERT)?

Performance test data are an important source of 

information that the EPA uses in compliance determinations, 

developing and reviewing standards, emission factor 

development, annual emission rate determinations and other 

purposes. In these activities, the EPA has found it 

ineffective and time consuming, not only for owners and 

operators, but also for regulatory agencies, to locate, 

collect and submit performance test data because of varied 

locations for data storage and varied data storage methods. 

In recent years, though, stack testing firms have typically 

collected performance test data in electronic format, 

making it possible to move to an electronic data submittal 

system that would increase the ease and efficiency of data 

submittal and improve data accessibility.

Through this proposal, the EPA is taking a step to 

increase the ease and efficiency of data submittal and 

improve data accessibility. Specifically, the EPA is 

proposing that owners and operators of oil and natural gas 

sector facilities submit electronic copies of required 

performance test reports to the EPA’s WebFIRE database. The 

WebFIRE database was constructed to store performance test 
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data for use in developing emission factors. A description 

of the WebFIRE database is available at 

http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. 

As proposed above, data entry would be through an 

electronic emissions test report structure called the 

Electronic Reporting Tool (ERT). The ERT will be able to 

transmit the electronic report through the EPA’s Central 

Data Exchange network for storage in the WebFIRE database

making submittal of data very straightforward and easy. A 

description of the ERT can be found at 

http://www.epa.gov/ttn/chief/ert/ert_tool.html.

The proposal to submit performance test data 

electronically to the EPA would apply only to those 

performance tests conducted using test methods that will be

supported by the ERT. The ERT contains a specific 

electronic data entry form for most of the commonly used 

EPA reference methods. A listing of the pollutants and test 

methods supported by the ERT is available at 

http://www.epa.gov/ttn/chief/ert/ert_tool.html. We believe 

that industry would benefit from this proposed approach to 

electronic data submittal. Having these data, the EPA would 

be able to develop improved emission factors, make fewer 

information requests, and promulgate better regulations. 
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One major advantage of the proposed submittal of

performance test data through the ERT is a standardized 

method to compile and store much of the documentation 

required to be reported by this rule. Another advantage is

that the ERT clearly states testing information that would 

be required. Another important benefit of submitting these 

data to the EPA at the time the source test is conducted is 

that it should substantially reduce the effort involved in 

data collection activities in the future. When the EPA has

performance test data in hand, there will likely be fewer 

or less substantial data collection requests in conjunction 

with prospective required residual risk assessments or 

technology reviews. This would result in a reduced burden 

on both affected facilities (in terms of reduced manpower 

to respond to data collection requests) and the EPA (in 

terms of preparing and distributing data collection 

requests and assessing the results).

State, local and tribal agencies could also benefit 

from more streamlined and accurate review of electronic 

data submitted to them. The ERT would allow for an 

electronic review process rather than a manual data

assessment making review and evaluation of the source 

provided data and calculations easier and more efficient. 
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Finally, another benefit of the proposed data submittal to 

WebFIRE electronically is that these data would greatly 

improve the overall quality of existing and new emissions

factors by supplementing the pool of emissions test data 

for establishing emissions factors and by ensuring that the 

factors are more representative of current industry 

operational procedures. A common complaint heard from 

industry and regulators is that emission factors are 

outdated or not representative of a particular source 

category. With timely receipt and incorporation of data 

from most performance tests, the EPA would be able to

ensure that emission factors, when updated, represent the 

most current range of operational practices. In summary, in 

addition to supporting regulation development, control 

strategy development and other air pollution control 

activities having an electronic database populated with 

performance test data would save industry, state, local, 

tribal agencies and the EPA significant time, money and 

effort while also improving the quality of emission 

inventories and, as a result, air quality regulations.

D. What are the innovative compliance approaches being 

considered?
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Given the potential number and diversity of sources 

affected by this action, we are exploring optional 

approaches to provide the regulated community, the 

regulators and the public a more effective mechanism that 

maximizes compliance and transparency while minimizing 

burden.

Under a traditional approach, owners or operators 

would provide notifications and keep records of information 

required by the NSPS. In addition, they would certify 

compliance with the NSPS as part of a required annual 

report that would include compliance-related information,

such as details of each well completion event and 

information documenting compliance with other requirements 

of the NSPS. The EPA, state or local agency would then 

physically inspect the affected facilities and/or audit the 

records retained by the owner or operator. As an 

alternative to the traditional approach, we are seeking an 

innovative way to provide for more transparency to the 

public and less burden on the regulatory agencies and 

owners and operators, especially as it relates to 

modification of existing sources through recompletions of 

hydraulically fractured gas wells. These innovative 

approaches would provide compliance assurance in light of 
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the absence of requirements for CAA title V permitting of 

non-major sources. 

Section V.E of this preamble discusses permitting 

implications associated with the NSPS and presents a 

proposed rationale for exempting non-major sources subject 

to the NSPS from title V permitting requirements. As 

discussed in sections V.A, V.C and VI.B of this preamble, 

the proposed NSPS will cover completions and recompletions 

of hydraulically fractured gas wells. We estimate that over 

20,000 completions and recompletions annually will be 

subject to the proposed requirements. As a result, we 

believe that notification and reporting associated with 

well completions must be streamlined to the extent possible 

to minimize undue burden on owners and operators, as well 

as state, local and tribal agencies. Though the 

requirements being proposed here are based on the 

traditional approach to compliance and do not include 

specific regulatory provisions for innovative compliance

tools, we have included discussions below that describe how 

some of these optional tools could work, and we will 

consider providing for such options in the final action. 

Further, we request comments and suggestions on all aspects 

of the innovative compliance approaches discussed below and 
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how they may be implemented appropriately. We are seeking 

comment regarding the scope of application of one or more 

of these approaches, i.e., which provisions of the 

standards being proposed here would be suitable for 

specific compliance approaches, and whether the approaches 

should be alternatives to the requirements in the 

regulations. 

The guiding principles we are following in considering 

these approaches to compliance are: (1) Simplicity and ease 

of understanding and implementation; (2) transparency and 

public accessibility; (3) electronic implementation where 

appropriate; and (4) encouragement of compliance by making 

compliance easier than noncompliance. Below are some tools 

that, when used in tandem with emissions limits and 

operational standards, the Agency believes could both 

assure compliance and transparency, while minimizing burden 

on affected sources and regulatory agencies.

1. Registration of Wells and Advance Notification of 

Planned Completions

Although the proposed NSPS will not require approval 

to drill or complete wells, it is important that regulatory 

agencies know when completions of hydraulically fractured 

wells are to be performed. Notification should occur 
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sufficiently in advance to allow for inspections or audits 

to certify or verify that the operator will have in place 

and use the appropriate controls during the completion. To 

that end, the proposed NSPS requires a 30-day advance 

notification of each completion or recompletion of a 

hydraulically fractured gas well. The advance notification 

would require that owners or operators provide the 

anticipated date of the completion, the geographic 

coordinates of the well and identifying information 

concerning the owner or operator and responsible company 

official. We believe this notification requirement serves 

as the registration requirement and could be streamlined 

through optional electronic reporting with web-based public 

access or other methods. We seek comment on potential 

methodologies that would minimize burden on operators,

while providing timely and useful information for 

regulators and the public. We also solicit comment on 

provisions for a follow-up notification one or two days 

before an impending completion via telephone or by 

electronic means, since it is difficult to predict exactly 

when a well will be ready for completion a month in 

advance. However, we would expect an owner or operator to 

provide the follow-up notification only in cases where the 
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completion date was expected to deviate from the original 

date provided. We ask for suggestions regarding how much 

advance notification is needed and the most effective 

method of providing sufficient and accurate advance 

notification of well completions. 

2. Third Party Verification

To complement the annual compliance certification 

required under the proposed NSPS, we are considering and 

seeking comment on the potential use of third party 

verification to assure compliance. Since the emission 

sources in the oil and natural gas sector, especially well 

completions, are widely geographically dispersed (often in 

very remote locations), compliance assurance can be very 

difficult and burdensome for state, local and tribal 

agencies and EPA permitting staff, inspectors and 

compliance officers. Additionally, we believe that 

verification of the data collection, compilation and 

calculations by an independent and impartial third party 

could facilitate the demonstration of compliance for the 

public. Verification of emissions data can also be 

beneficial to owners and operators by providing certainty 

of compliance status.

As mentioned above, notification and reporting 
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requirements associated with well completions are likely 

applications for third party verification used in tandem 

with the required annual compliance certification. The 

third party verification program could be used in a variety 

of ways to ease regulatory burden on the owners and 

operators and to leverage compliance assurance efforts of 

the EPA and state, local and tribal agencies. The third 

party agent could serve as a clearinghouse for 

notifications, records and annual compliance certifications 

submitted by owners and operators. This would provide 

online access to completion information by regulatory 

agencies and the public. Having notifications submitted to 

the clearinghouse would relieve state, local and tribal 

agencies of the burden of receiving thousands of paper or 

email well completion notifications each year, yet still 

provide them quick access to the information. Using a third 

party agent, it is possible that notifications of well 

completions could be submitted with an advance period much 

less than 30 days that could make a 2 day follow-up 

notification unnecessary. The clearinghouse could also 

house information on past completions and copies of 

compliance certifications. We seek comment on whether 

annual reports for well completions would be needed if a 
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suitable third party verification program was in place and 

already housed that same information. We also solicit 

comment on the range of potential activities the third 

party verification program could handle with regard to well 

completions. 

In this proposed action, there are also provisions for 

applying third party verification to the required 

electronic reporting using the ERT (see section V.C.3 above 

for a discussion of the ERT). As stated above, all sources 

must use the ERT to submit all performance test reports 

(required in 40 CFR parts 60, 61 and 63) to the EPA. There 

is an option in the ERT for state, local and tribal 

agencies to review and verify that the information 

submitted to the EPA is truthful, accurate and complete. 

Third party verifiers could be contractors or other 

personnel familiar with oil and natural gas exploration and 

production. We are seeking comment on appropriate third 

party reviewers and qualifications and registration 

requirements under such a program. We want to state clearly 

here that third party verification would not supersede or 

substitute for inspections or audit of data and information 

by state, local and tribal agencies and the EPA. 

Potential issues with third party verification include 
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costs incurred by industry and approval of third party 

verifiers. The cost of third party verification would be 

borne by the affected industries. We are seeking comment on 

whether third party verification paid for by industry would 

result in impartial, accurate and complete data 

information. The EPA, working with state, local and tribal 

agencies and industry, would expect to develop guidance for 

third party verifiers. We are seeking comment on whether or 

not the EPA should approve third party verifiers. 

3. Electronic Reporting Using Existing Mechanisms

The proposed 40 CFR part 60, subpart OOOO and final 

Greenhouse Gas (GHG) Mandatory Reporting Rule, 40 CFR part 

98, subpart W, provide details on flare and vented emission 

sources and how to estimate their emissions. We solicit 

comment on requiring sources to electronically submit their 

emissions data for the oil and gas rules proposed here. The 

EPA’s Electronic Greenhouse Gas Reporting Tool (e-GGRT) for 

40 CFR part 98, subpart W, while used to report emissions 

at the emissions source level (e.g., well completions, well 

unloading, compressors, gas plant leaks, etc.), will 

aggregate emissions at the basin level for e-reporting 

purposes. As a result, it may be difficult to merge 

reporting under NSPS subpart OOOO with GHG Reporting Rule 
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subpart W methane reporting, especially if manual reporting 

is used. However, since the operator would have these 

emissions details at the individual well level (because 

that will be how they would develop their basin-wide 

estimates), we do not believe it would be a significant 

burden to require owners or operators to report the data 

they already have for subpart W in an ERT for NSPS and 

NESHAP compliance purposes. However, if the e-GGRT is not 

structured to provide for reporting of other pollutants 

besides GHG (e.g., VOC and HAP), then there may be some 

modification of the database required to accommodate the 

other pollutants.

4. Provisions for Encouraging Innovative Technology

The oil and natural gas industry has a long history of 

innovation in developing new exploration and production 

methods, along with techniques to minimize product losses 

and reduce adverse environmental impacts. These efforts are 

often undertaken with tremendous amounts of research, 

including pilot applications at operating facilities in the 

field. Absent regulation, these developmental activities, 

some of which ultimately are not successful, can proceed 

without risk of violation of any standards. However, as 

more emission sources in this source category are covered 
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by regulation, as in the case of the action being proposed 

here, there likely will be situations where innovation and 

development of new control techniques potentially could be 

stifled by risk of violation. 

We believe it is important to facilitate, not hinder, 

innovation and continued development of new technology that 

can result in enhanced environmental performance of 

facilities and sources affected by the EPA’s regulations. 

However, any approaches to accommodate technology 

development must be designed and implemented in accordance 

with the CAA and other statutes. We seek comment on 

approaches that may be suitable for allowing temporary 

field testing of technology in development. These 

approaches could include not only established procedures 

under the CAA and its implementing regulations, but new 

ways to apply or interpret these provisions to avoid 

impeding innovation while remaining environmentally 

responsible and legal. 

E. How does the NSPS Relate to Permitting of Sources?

1. How does this action affect permitting requirements?

The proposed rules do not change the Federal 

requirements for determining whether oil and gas sources 

are major sources for purposes of nonattainment major New 
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Source Review (NSR), prevention of significant 

deterioration, CAA title V, or HAP major sources pursuant 

to CAA section 112. Specifically, if an owner or operator 

is not currently required to get a major NSR or title V 

permit for oil and gas sources, including well completions, 

it would not be required to get a major NSR or title V 

permit as a result of these proposed standards. EPAapproved state and local major source permitting programs 

would not be affected. That is, state and local agencies 

with EPA-approved programs will still make case-by-case

major source determinations for purposes of major NSR and 

title V, relying on the regulatory criteria, as explained 

in the McCarthy Memo.6 Consistent with the McCarthy Memo, 

whether or not a permitting authority should aggregate two 

or more pollutant-emitting activities into a single major 

stationary source for purposes of NSR and title V remains a 

case-by-case decision in which permitting authorities 

retain the discretion to consider the factors relevant to 

the specific circumstances of the permitted activities.

In addition, the proposed standards would not change 

the requirements for determining whether oil and gas 

 

6

Withdrawal of Source Determinations for Oil and Gas Industries, 

September 22, 2009. This memo continues to articulate the 

Agency’s interpretation for major NSR and title V permitting of 

oil and gas sources.
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sources are subject to minor NSR. Nor would the proposed 

standards affect existing EPA-approved state and local 

minor NSR rules, as well as policies and practices 

implementing those rules. Many state and local agencies 

have already adopted minor NSR permitting programs that 

provide for control of emissions from relatively small 

emission sources, including various pieces of equipment 

used in oil and gas fields. State and local agencies would 

be able to continue to use any EPA-approved General 

Permits, Permits by Rule, and other similar streamlining 

mechanisms to permit oil and gas sources such as wells. We 

recently promulgated the final Tribal Minor NSR rules for 

use in issuing minor issue permits on tribal lands, where 

many oil and gas sources are located. 

The proposed standards will lead to better control of 

and reduced emissions from oil and gas production, gas 

processing and transmission and storage, including wells. 

In some instances, we anticipate that complying with the 

NSPS would reduce emissions from these smaller sources to 

below the minor source applicability thresholds. In those 

cases, sources that would otherwise have been subject to 

minor NSR would not need to get minor NSR permits as a 

result of being subject to the NSPS. Accordingly, the 
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number of minor NSR permits, as well as the Agency 

resources needed to issue them, would be reduced. 

We expect the emission reductions achieved from the 

proposed standards to significantly improve ozone 

nonattainment problems in areas where oil and gas 

production occurs. Strategies for attaining and maintaining 

the national ambient air quality standards (NAAQS) are a 

function of SIP (or, in some instances, Federal 

Implementation Plans and Tribal Implementation Plans) 

pursuant to CAA section 110. In developing plans to attain 

and maintain the NAAQS, EPA works with state, local or 

Tribal agencies to account for growth and develop overall 

control strategies that address existing and expected 

emissions. The reductions achieved by the standards will 

make it easier for state and local agencies to plan for and 

to attain and maintain the ozone NAAQS.

2. How does this action affect applicability of CAA title 

V?

Under section 502(a) of the CAA, the EPA may exempt 

one or more non-major sources7 subject to CAA section 111 

(NSPS) standards from the requirements of title V if the 

EPA finds that compliance with such requirements is 

 

7

CAA section 502(a) prohibits title V exemption for any major 

source, which is defined in CAA section 501(2) and 40 CFR 70.2. 
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"impracticable, infeasible, or unnecessarily burdensome" on 

such sources. The EPA determine whether to exempt a nonmajor source from title V at the time we issue the relevant 

CAA section 111 standards (40 CFR 70.3(b)(2)). We are 

proposing in this action to exempt from the requirements of 

title V non-major sources that would be subject to the 

proposed NSPS for well completions, pneumatic devices, 

compressors, and/or storage vessels. These non-major 

sources (hereinafter referred to as the “oil and gas NSPS 

non-major sources”) would not be required to obtain title V 

permits solely as a result of being subject to one or more 

of the proposed NSPS identified above (hereinafter referred 

to as the “proposed NSPS”); however, if they were otherwise 

required to obtain title V permits, such requirement(s) 

would not be affected by the proposed exemption.

Consistent with the statute, the EPA believes that 

compliance with title V permitting is "unnecessarily 

burdensome" for the oil and gas NSPS non-major sources. The 

EPA's inquiry into whether this criterion was satisfied is

based primarily upon consideration of the following four 

factors: (1) Whether title V would result in significant 

improvements to the compliance requirements that we are 

proposing for the oil and gas NSPS affected non-major 
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sources; (2) whether title V permitting would impose a 

significant burden on these non-major sources and whether 

that burden would be aggravated by any difficulty these 

sources may have in obtaining assistance from permitting 

agencies; (3) whether the costs of title V permitting for 

these non-major sources would be justified, taking into 

consideration any potential gains in compliance likely to 

occur for such sources; and (4) whether there are 

implementation and enforcement programs in place that are 

sufficient to assure compliance with the proposed Oil and 

Natural Gas NSPS without relying on title V permits. Not 

all of the four factors must weigh in favor of an 

exemption. See 70 FR 75320, 75323 (Title V Exemption Rule).

Instead, the factors are to be considered in combination

and the EPA determines whether the factors, taken together, 

support an exemption from title V for the oil and gas nonmajor sources. Additionally, consistent with the guidance 

provided by the legislative history of CAA section 502(a),8

we considered whether exempting the Oil and Natural Gas 

NSPS non-major sources would adversely affect public 

 

8

The legislative history of section 502(a) suggests that EPA 

should not grant title V exemptions where doing so would 

adversely affect public health, welfare or the environment. (See 

Chafee-Baucus Statement of Senate Managers, Environment and 

Natural Resources Policy Division 1990 CAA Leg. Hist. 905, 

Compiled November 1993.)
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health, welfare or the environment. The first factor is 

whether title V would result in significant improvements to 

the compliance requirements in the proposed NSPS. A finding 

that title V would not result in significant improvements 

to the compliance requirements in the proposed NSPS would 

support a conclusion that title V permitting is 

"unnecessary" for non-major sources subject to the Oil and 

Natural Gas Production NSPS. 

One way that title V may improve compliance is by 

requiring monitoring (including recordkeeping designed to 

serve as monitoring) to assure compliance with permit terms 

and conditions reflecting the emission limitations and 

control technology requirements imposed in the standard. 

See 40 CFR 70.6(c)(1) and 40 CFR 71.6(c)(1). The "periodic 

monitoring" provisions of 40 CFR 70.6(a)(3)(i)(B) and 40 

CFR 71.6(a)(3)(i)(B) require new monitoring to be added to 

the permit when the underlying standard does not already 

require “periodic testing or instrumental or 

noninstrumental monitoring (which may consist of 

recordkeeping designed to serve as monitoring)." In 

addition, title V imposes a number of recordkeeping and 

reporting requirements that may be important for assuring 

compliance. These include requirements for a monitoring 
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report at least every 6 months, prompt reports of 

deviations, and an annual compliance certification. See 40 

CFR 70.6(a)(3) and 40 CFR 71.6(a)(3), 40 CFR 70.6(c)(1) and 

40 CFR 71.6(c)(1), and 40 CFR 70.6(c)(5) and 40 CFR 

71.6(c)(5). To determine whether title V permits would add 

significant compliance requirements to the proposed NSPS, 

we compared the title V monitoring, recordkeeping and 

reporting requirements mentioned above to those 

requirements proposed for the Oil and Natural Gas NSPS 

affected facilities. 

For wellhead affected facilities (well completions), 

the proposed NSPS would require (1) 30-day advance 

notification of each well completion to be performed; (2) 

noninstrumental monitoring, which is achieved through 

documentation and recordkeeping of procedures followed 

during each completion, including total duration of the 

completion event, amount of time gas is recovered using 

reduced emission completion techniques, amount of time gas 

is combusted, amount of time gas is vented to the 

atmosphere and justification for periods when gas is 

combusted or vented rather than being recovered; (3) 

reports of cases where well completions were not performed 

in compliance with the NSPS; (4) annual reports that 
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document all completions performed during the reporting 

period (a single report may be used to document multiple 

completions conducted by a single owner or operator during 

the reporting period); and (5) annual compliance 

certifications submitted with the annual report. 

These monitoring, recordkeeping and reporting 

requirements in the proposed NSPS for well completions are 

sufficient to ensure that the Administrator, the state, 

local and tribal agencies and the public are aware of 

completion events before they are performed to provide

opportunity for inspection. Sufficient documentation would 

also be required to be retained and reported to the 

Administrator to assure compliance with the NSPS for well 

completions. In light of the above, we have determined that 

additional monitoring through title V is not needed and 

that the monitoring, recordkeeping and reporting 

requirements described above are sufficient to assure 

compliance with the proposed requirements for well 

completions. 

With respect to storage vessels, the proposed NSPS 

would require 95-percent control of VOC emissions. The 

proposed standard could be met by a vapor recovery unit, a 

flare control device or other control device. The proposed 
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NSPS would require an initial performance test followed by 

continuous monitoring of the control device used to meet 

the 95-percent control. We believe that the monitoring 

requirements described above are sufficient to assure 

compliance with the proposed NSPS for storage vessels and, 

therefore, additional monitoring through title V is not 

needed. In addition to monitoring, as part of the first 

factor, we have considered the extent to which title V 

could potentially enhance compliance through recordkeeping 

or reporting requirements. The proposed NSPS would require 

(1) construction, startup and modification notifications, 

as required by 40 CFR 60.7(a); and (2) annual reports that 

identify all storage vessel affected facilities of the 

owner or operator and documentation of periods of noncompliance. The proposed NSPS would also require records 

documenting liquid throughput of condensate or crude oil 

(to determine applicability), as provided for in the 

proposed rule. Recordkeeping would also include records of 

the initial performance test and other information that 

document compliance with applicable emission limit. These 

requirements are similar to those under title V. In light 

of the above, we believe that the monitoring, recordkeeping 

and reporting requirements described above are sufficient 
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to assure compliance with the proposed NSPS for storage 

vessels.

For pneumatic controllers, centrifugal compressors and 

reciprocating compressors, the proposed NSPS are in the 

form of operational, work practice or equipment standards.9

For each of these affected facilities, the proposed NSPS 

would require: (1) Construction, startup and modification 

notifications, as required by 40 CFR 60.7(a); (2) annual 

reports; (3) for each pneumatic controller installed or 

modified (including replacement of an existing controller), 

records of location and date of installation and 

documentation that each controller emits no more than the 

applicable emission limit or is exempt (with rationale for 

the exemption); (4) for each centrifugal compressor, 

records that document that each new or modified compressor 

is equipped with dry seals; and (5) for each new or 

modified reciprocating compressor, records of rod packing 

replacement, including elapsed operating hours since the 

previous rod packing installation.

For these other affected sources described above, the 

proposed NSPS provide monitoring in the form of 

 

9

The proposed numeric standards for pneumatic controllers 

reflect the use of specific equipment (either non-gas driven

device or low-bleed device).
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recordkeeping (as described above) that would assure 

compliance with the proposed operational, work practice or 

equipment standards. Monitoring by means other than 

recordkeeping would not be practical or appropriate for 

these standards. Records are required to ensure that these 

standards and practices are followed. We believe that the 

monitoring, recordkeeping and reporting requirements 

described above are sufficient to assure compliance with 

the proposed NSPS for pneumatic controllers and 

compressors. 

We acknowledge that title V might provide for 

additional compliance requirements for these non-major 

sources, but we have determined, as explained above, that 

the monitoring, recordkeeping and reporting requirements in 

this proposed NSPS are sufficient to assure compliance with 

the proposed standards for well completions, storage 

vessels, pneumatic controllers and compressors. Further, 

given the nature of some of the operations and the types of 

the requirements at issue, the additional compliance 

requirements under title V would not significantly improve 

the compliance requirements in this proposed NSPS. For 

instance, well completions occur over a very short period 

(generally 3 to 10 days), and the proposed NSPS for 
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pneumatic controllers and centrifugal compressors can be 

met by simply installing the equipment that meet the 

proposed emission limit; therefore, the semi-annual 

reporting requirement under title V would not improve 

compliance with these proposed NSPS and, in fact, may seem 

inappropriate for such short term operations.

For the reasons stated above, we believe that title V 

would not result in significant improvements to the 

compliance requirements that are provided in this proposed 

NSPS. Therefore, the first factor supports a conclusion 

that title V permitting is "unnecessary" for non-major

sources subject to the Oil and Natural Gas NSPS.

The second factor we considered is whether title V

permitting would impose significant burdens on the oil and 

natural gas NSPS non-major sources and whether that burden 

would be aggravated by any difficulty these sources may 

have in obtaining assistance from permitting agencies. 

Subjecting any source to title V permitting imposes certain 

burdens and costs that do not exist outside of the title V 

program. EPA estimated that the average cost of obtaining 

and complying with a title V permit was $65,700 per source 

for a 5-year permit period, including fees. See Information 

Collection Request (ICR) for Part 70 Operating Permit 
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Regulations, January 2007, EPA ICR Number 1587.07. EPA does 

not have specific estimates for the burdens and costs of 

permitting the oil and gas NSPS non-major sources; however, 

there are certain activities associated with the 40 CFR 

part 70 and 40 CFR part 71 rules. These activities are 

mandatory and impose burdens on the any facility subject to 

title V. They include reading and understanding permit 

program regulations; obtaining and understanding permit 

application forms; answering follow-up questions from 

permitting authorities after the application is submitted; 

reviewing and understanding the permit; collecting records; 

preparing and submitting monitoring reports; preparing and 

submitting prompt deviation reports, as defined by the 

state, which may include a combination of written, verbal 

and other communications methods; collecting information, 

preparing and submitting the annual compliance 

certification; preparing applications for permit revisions 

every 5 years; and, as needed, preparing and submitting 

applications for permit revisions. In addition, although 

not required by the permit rules, many sources obtain the 

contractual services of consultants to help them understand 

and meet the permitting program's requirements. The ICR for 

40 CFR part 70 provides additional information on the 
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overall burdens and costs, as well as the relative burdens 

of each activity described here. Also, for a more 

comprehensive list of requirements imposed on 40 CFR part 

70 sources (hence, burden on sources), see the requirements 

of 40 CFR 70.3, 40 CFR 70.5, 40 CFR 70.6, and 40 CFR 70.7.

The activities described above, which are quite extensive 

and time consuming, would be a significant burden on the 

non-major sources that would be subject to the proposed 

NSPS, in particular for well completion and/or pneumatic 

devices, considering the short duration of a well 

completion and the one time equipment installation of a 

pneumatic controller for meeting the proposed NSPS. 

Furthermore, some of the non-major sources that would be 

subject to the proposed NSPS may be small entities that may 

lack the technical resources and, therefore, need 

assistance from the permitting authorities to comply with 

the title V permitting requirements. Based on our 

projections, over 20,000 well completions (for both new 

hydraulically fractured gas wells and for existing gas 

wells that are subsequently fractured or re-fractured) will 

be performed each year. For pneumatic controller affected 

facilities, we estimate that approximately 14,000 new 

controllers would be subject to the NSPS each year. Our 
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estimated numbers of affected facilities that would be 

subject to the proposed NSPS for storage vessels and 

compressors are smaller (around 500 compressors and 300 

storage vessels). Although we do not know the total number 

of non-major sources that would be subject to the proposed 

NSPS, based on the estimated numbers of affected 

facilities, we anticipate a significant increase in the 

number of permit applications that permitting authorities 

would have to process each year. This significant burden on 

the permitting authorities raises a concern with the 

potential difficulty or delay that the small entities may 

face in obtaining sufficient assistance from the permitting 

authorities. 

The third factor we considered is whether the costs of

title V permitting for these area sources would be 

justified, taking into consideration any potential gains in 

compliance likely to occur for such sources. We concluded,

in considering the first factor, that the monitoring, 

recordkeeping and reporting requirements in this proposed 

NSPS assure compliance with the proposed standards, that 

title V would not result in significant improvement to 

these compliance requirements and, that, in some instances, 

certain title V compliance requirements may not be 
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appropriate. In addition, as discussed above in our 

consideration of the second factor, we have concerns with 

the potential burdens that title V may impose on these 

sources. In addition, below in our consideration of the 

fourth factor, we find that there are adequate 

implementation and enforcement programs in place to assure 

compliance with the proposed NSPS. In light of the above, 

we find that the costs of title V permitting are not 

justified for the sources we propose to exempt. 

Accordingly, the third factor supports title V exemption 

for the oil and gas NSPS non-major sources. 

The fourth factor we considered is whether there are

implementation and enforcement programs in place that are 

sufficient to assure compliance with the proposed NSPS for 

oil and gas sources without relying on title V permits. 

The CAA provides States the opportunity to take delegation 

of NSPS. Before the EPA will delegate the program, the EPA 

will evaluate the state programs to ensure that states have 

adequate capability to enforce the CAA section 111

regulations and provide assurances that they will enforce 

the NSPS. In addition, EPA retains authority to enforce 

this NSPS anytime under CAA sections 111, 113 and 114. 

Accordingly, we can enforce the monitoring, recordkeeping 
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and reporting requirements, which, as discussed under the 

first factor, are adequate to assure compliance with this 

NSPS. Also, states and the EPA often conduct voluntary 

compliance assistance, outreach and education programs 

(compliance assistance programs), which are not required by 

statute. We determined that these additional programs will 

supplement and enhance the success of compliance with these 

proposed standards. We believe that the statutory 

requirements for implementation and enforcement of this 

NSPS by the delegated states, the EPA and the additional 

assistance programs described above together are sufficient 

to assure compliance with these proposed standards without 

relying on title V permitting. 

Our balance of the four factors strongly supports a 

finding that title V is unnecessarily burdensome for the 

oil and gas non-major sources. While title V might add 

additional compliance requirements if imposed, we believe 

that there would not be significant improvements to the 

compliance requirements in this proposed rule because the 

proposed rule requirements are specifically designed to 

assure compliance with the proposed NSPS and, as explained 

above, some of the title V requirements may not be 

appropriate for certain operations and/or proposed 
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standards. We are also concerned with the potential burden 

that title V may impose on some of these sources. In light 

of little or no potential gain in compliance if title V 

were required, we do not believe that the costs of title V 

permitting is justified in this case. Finally, there are 

adequate implementation and enforcement programs in place 

to assure compliance with these proposed standards. Thus, 

we propose that title V permitting is "unnecessarily 

burdensome" for the oil and gas non-major sources. 

In addition to evaluating whether compliance with 

title V requirements is "unnecessarily burdensome," EPA 

also considered, consistent with guidance provided by the 

legislative history of section 502(a), whether exempting

oil and gas NSPS non-major sources from title V 

requirements would adversely affect public health, welfare

or the environment. The title V permit program does not 

impose new substantive air quality control requirements on 

sources, but instead requires that certain procedural 

measures be followed, particularly with respect to 

determining compliance with applicable requirements. As 

stated in our consideration of factor one, title V would 

not lead to significant improvements in the compliance 

requirements for the proposed NSPS. For the reason stated 
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above, we believe that exempting these non-major sources 

from title V permitting requirements would not adversely 

affect public health, welfare or the environment.

On the contrary, we are concerned that requiring title 

V in this case could potentially adversely affect public 

health, welfare or the environment. As mentioned above, we 

anticipate a significant increase in the number of permit 

applications that permitting authorities would have to 

process each year. Depending on the number of non-major 

sources that would be subject to this rule, requiring 

permits for those sources, at least in the first few years 

of implementation, could potentially adversely affect 

public health, welfare or the environment by shifting state 

agencies resources away from assuring compliance for major 

sources (which cannot be exempt from title V) to issuing 

new permits for these non-major sources, potentially 

reducing overall air program effectiveness. 

Based on the above analysis, we conclude that title V 

permitting would be "unnecessarily burdensome" for oil and 

gas NSPS non-major sources. We are, therefore, proposing 

that these non-major sources be exempt from title V 

permitting requirements.

VI. Rationale for Proposed Action for NSPS
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A. What did we evaluate relative to NSPS?

As noted above, there are two existing NSPS that 

address emissions from the Oil and Natural Gas source 

category. These NSPS are relatively narrow in scope, as 

they address emissions only at natural gas processing 

plants. Specifically, 40 CFR part 60, subpart KKK addresses 

VOC emissions from leaking equipment at onshore natural gas 

processing plants and 40 CFR part 60, subpart LLL addresses 

SO2 emissions from natural gas processing plants.

CAA section 111(b)(1)(B) requires the EPA to review 

and revise, if appropriate, NSPS standards. Accordingly, we 

evaluated whether the existing NSPS reflect the BSER for 

the emission sources that they address. This review was 

conducted by examining currently used, new and emerging 

control systems and assessing whether they represent 

advances in emission reduction techniques from those upon 

which the existing NSPS are based, including advances in 

LDAR approaches and SO2 control at natural gas processing 

plants. For each new or emerging control option identified, 

we then evaluated emission reductions, costs, energy 

requirements and nonair quality impacts, such as solid 

waste generation.
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In this package, we have also evaluated whether there 

were additional pollutants emitted by facilities in the Oil 

and Natural Gas source category that warrant regulation and 

for which we have adequate information to promulgate 

standards of performance. Finally, we have identified 

additional processes in the Oil and Natural Gas source 

category for which it may be appropriate to develop 

performance standards. This would include processes that 

emit the currently regulated pollutants, VOC and SO2, as 

well as any additional pollutants for which we determined 

regulation to be appropriate.

B. What are the results of our evaluations and proposed 

actions relative to NSPS? 

1. Do the existing NSPS reflect the BSER for sources 

covered?

Consistent with our obligations under CAA section 

111(b), we evaluated whether the control options reflected 

in the current NSPS for the Oil and Natural Gas source

category still represent BSER. To evaluate the BSER options 

for equipment leaks, we reviewed EPA’s current LDAR 

programs, the Reasonably Available Control Technology 

(RACT)/Best Available Control Technology (BACT)/Lowest 

Achievable Emission Rate (LAER) Clearinghouse (RBLC)
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database, and emerging technologies that have been 

identified by partners in the Natural Gas STAR program. 

The current NSPS for equipment leaks of VOC at natural 

gas processing plants (40 CFR part 60, subpart KKK) 

requires compliance with specific provisions of 40 CFR part 

60, subpart VV, which is a LDAR program, based on the use 

of EPA Method 21 to identify equipment leaks. In addition 

to the subpart VV requirements, we reviewed the LDAR 

requirements in 40 CFR part 60, subpart VVa. This LDAR 

program is considered to be more stringent than the subpart 

VV requirements, because it has lower component leak 

threshold definitions and more frequent monitoring, in 

comparison to the subpart VV program. Furthermore, subpart 

VVa requires monitoring of connectors, while subpart VV 

does not. We also reviewed options based on optical gas 

imaging. 

As mentioned above, the currently required LDAR 

program for natural gas processing plants (40 CFR part 60, 

subpart KKK) is based on EPA Method 21, which requires the 

use of an organic vapor analyzer to monitor components and 

to measure the concentration of the emissions in 

identifying leaks. We recognize that there have been 

advancements in the use of optical gas imaging to detect 
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leaks from these same types of components. These 

instruments do not yet provide a direct measure of leak 

concentrations. The instruments instead provide a measure 

of a leak relative to an instrument specific calibration 

point. Since the promulgation of 40 CFR part 60, subpart 

KKK (which requires Method 21 leak measurement monthly), 

the EPA has updated the 40 CFR part 60 General Provisions 

to allow the use of advanced leak detection tools, such as 

optical gas imaging and ultrasound equipment as an 

alternative to the LDAR protocol based on Method 21 leak 

measurements (see 40 CFR 60.18(g)). The alternative work 

practice allowing use of these advanced technologies 

includes a provision for conducting a Method 21-based LDAR 

check of the regulated equipment annually to verify good 

performance. 

In our review, we evaluated 4 options in considering 

BSER for VOC equipment leaks at natural gas processing 

plants. One option we evaluated consists of changing from a 

40 CFR part 60, subpart VV-level program, which is what 40 

CFR part 60, subpart KKK currently requires, to a 40 CFR 

part 60, subpart VVa program, which applies to new 

synthetic organic chemical plants after 2006. Subpart VVa 

lowers the leak definition for valves from 10,000 parts per 
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million (ppm) to 500 ppm, and requires the monitoring of 

connectors. In our analysis of these impacts, we estimated 

that, for a typical natural gas processing plant, the 

incremental cost effectiveness of changing from the current 

subpart VV-level program to a subpart VVa-level program 

using Method 21 is $3,352 per ton of VOC reduction. 

In evaluating 40 CFR part 60, subpart VVa-level LDAR 

at processing plants, we also analyzed separately the 

individual types of components (valves, connectors, 

pressure relief devices and open-ended lines) to determine 

cost effectiveness for individual components. Detailed

discussions of these component-by-component analyses are 

included in the TSD in the docket. Cost effectiveness 

ranged from $144 per ton of VOC (for valves) to $4,360 per 

ton of VOC (for connectors), with no change in requirements 

for pressure relief devices and open-ended lines. 

Another option we evaluated for gas processing plants 

was the use of optical gas imaging combined with an annual 

EPA Method 21 check (i.e., the alternative work practice 

for monitoring equipment for leaks at 40 CFR 60.18(g)). We 

had previously determined that the VOC reduction achieved 

by this combination of optical gas imaging and Method 21 

would be equivalent to reductions achieved by the 40 CFR 
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part 60, subpart VVa-level program. Based on that emission 

reduction level, we determined the cost effectiveness of 

this option to be $6,462 per ton of VOC reduction. This 

analysis is based on the facility purchasing an optical gas 

imaging system costing $85,000. However, we identified at 

least one manufacturer who rents the optical gas imaging 

systems. That manufacturer rents the optical gas imaging 

system for $3,950 per week. Using this rental cost in place 

of the purchase cost, the VOC cost effectiveness of the 

monthly optical gas imaging combined with annual Method 21 

checks is $4,638 per ton of VOC reduction.10 A third option 

we evaluated consisted of monthly optical gas imaging 

without an annual Method 21 check. We estimated the annual 

cost of the monthly optical gas imaging LDAR program to be 

$76,581, based on camera purchase, or $51,999, based on 

camera rental. However, because we were unable to estimate 

the VOC emissions achieved by an optical imaging program 

alone, we were unable to estimate the cost effectiveness of

this option.

Finally, we evaluated a fourth option similar to the 

third option, except that the optical gas imaging would be 

 

10 Because optical gas imaging is used to view several pieces of 

equipment at a facility at once to survey for leaks, options 

involving imaging are not amenable to a component by component 

analysis.
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performed annually rather than monthly. For this option, we 

estimated the annual cost to be $43,851, based on camera 

purchase, or $18,479, based on camera rental.

We request comment on the applicability of a LDAR

program based solely on the use of optical gas imaging. Of 

most use to us would be information on the effectiveness of 

this and, potentially, other advanced measurement 

technologies, to detect and repair small leaks on the same 

order or smaller than specified in the 40 CFR part 60, 

subpart VVa equipment leak requirements and the effects of 

increased frequency of and associated leak detection, 

recording and repair practices.

Because we could not estimate the cost effectiveness 

of options 3 and 4, we could not identify either of these 

two options as BSER for reducing VOC leaks at gas 

processing plants. Because options 1 and 2 have achieve 

equivalent VOC reduction and are both cost effective, we 

believe that both options 1 and 2 reflect BSER for LDAR for 

natural gas processing plants. As mentioned above, option 1 

is the LDAR in 40 CFR part 60, subpart VVa and option 2 is 

the alternative work practice at 40 CFR 60.18(g) and is 

already available to use as an alternative to subpart VVa 

LDAR. Therefore, we propose that the NSPS for equipment 
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leaks of VOC at gas processing plants be revised to require 

compliance with the subpart VVa equipment leak 

requirements.

For 40 CFR part 60, subpart LLL, we reviewed control 

systems for SO2 emissions from sweetening units located at 

natural gas processing plants, including those followed by 

a sulfur recovery unit. Subpart LLL provides specific 

standards for SO2 emission reduction efficiency, on the 

basis of sulfur feed rate and the sulfur content of the 

natural gas. 

According to available literature, the most widely 

used process for converting H2S in acid gases (i.e., H2S 

and CO2) separated from natural gas by a sweetening process 

(such as amine treating) into elemental sulfur is the Claus 

process. Sulfur recovery efficiencies are higher with 

higher concentrations of H2S in the feed stream due to the 

thermodynamic equilibrium limitation of the Claus process. 

The Claus sulfur recovery unit produces elemental sulfur 

from H2S in a series of catalytic stages, recovering up to 

97-percent recovery of the sulfur from the acid gas from 

the sweetening process. Further, sulfur recovery is 

accomplished by making process modifications or by 
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employing a tail gas treatment process to convert the 

unconverted sulfur compounds from the Claus unit. 

We evaluated process modifications and tail gas 

treatment options when we proposed 40 CFR part 60, subpart 

LLL. 49 FR 2656, 2659-2660 (1984). As we explained in the 

preamble to the proposed subpart LLL, control through 

sulfur recovery with tail gas treatment may not always be

cost effective, depending on sulfur feed rate and inlet H2S 

concentrations. Therefore, other methods of increasing 

sulfur recovery via process modifications were evaluated. 

As shown in the original evaluation, the performance 

capabilities and costs of each of these technologies are 

highly dependent on the ratio of H2S and CO2 in the gas 

stream and the total quantity of sulfur in the gas stream 

being treated. The most effective means of control was 

selected as BSER for the different stream characteristics. 

As a result, separate emissions limitations were developed 

in the form of equations that calculate the required 

initial and continuous emission reduction efficiency for 

each plant. The equations were based on the design 

performance capabilities of the technologies selected as 

BSER relative to the gas stream characteristics. 49 FR 

2656, 2663-2664 (1984). The emission limit for sulfur feed 
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rates at or below 5 long tons per day, regardless of H2S

content, was 79 percent. For facilities with sulfur feed 

rates above 5 long tons per day, the emission limits ranged 

from 79 percent at an H2S content below 10 percent to 99.8 

percent for H2S contents at or above 50 percent.

To review these emission limitations, we performed a 

search of the RBLC database and state regulations. No state 

regulations identified had emission limitations more 

stringent than 40 CFR part 60, subpart LLL. However, the 

RBLC database search identified two entries with SO2

emission reductions of 99.9 percent. One entry is for a 

facility in Bakersfield, California, with a 90 long ton per 

day sulfur recovery unit followed by an amine-based tailgas treating unit. The second entry is for a facility in 

Coden, Alabama, with a sulfur recovery unit with a sulfur 

feed rate of 280 long tons per day, followed by selective 

catalytic reduction and a tail gas incinerator. However, 

neither of these entries contained information regarding 

the H2S contents of the feed stream. Because the sulfur 

recovery efficiency of these large sized plants was greater 

than 99.8 percent, we reevaluated the original data. Based 

on the available cost information, it appears that a 99.9-

percent efficiency is cost effective for facilities with a 
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sulfur feed rate greater than 5 long tons per day and H2S 

content equal to or greater than 50 percent. Based on our 

review, we are proposing that the maximum initial and 

continuous efficiency for facilities with a sulfur feed 

rate greater than 5 long tons per day and a H2S content 

equal to or greater than 50 percent be raised to 99.9 

percent. We are not proposing to make changes to the 

equations.

Our search of the RBLC database did not uncover 

information regarding costs and achievable emission 

reductions to suggest that the emission limitations for 

facilities with a sulfur feed rate less than 5 long tons 

per day or H2S content less than 50 percent should be 

modified. Therefore, we are not proposing any changes to 

the emissions limitations for facilities with sulfur feed 

rate and H2S content less than 5 long tons per day and 50 

percent, respectively.

2. What pollutants are being evaluated in this Oil and 

Natural Gas NSPS package?

The two current NSPS for the Oil and Natural Gas 

source category address emissions of VOC and SO2. In 

addition to these pollutants, sources in this source 

category also emit a variety of other pollutants, most 
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notably, air toxics. As discussed elsewhere in this notice, 

there are NESHAP that address air toxics from the oil and 

natural gas sector.

In addition, processes in the Oil and Natural Gas 

source category emit significant amounts of methane. The 

1990 - 2009 U.S. GHG Inventory estimates 2009 methane 

emissions from Petroleum and Natural Gas Systems (not 

including petroleum refineries) to be 251.55 MMtCO2e 

(million metric tons of CO2-equivalents (CO2e)).

11 The 

emissions estimated from well completions and recompletions

exclude a significant number of wells completed in tight

sand plays, such as the Marcellus, due to availability of 

data when the 2009 Inventory was developed. The estimate 

in this proposal includes an adjustment for tight sand

plays (being considered as a planned improvement in

development of the 2010 Inventory). This adjustment would

increase the 2009 Inventory estimate by 76.74 MMtCO2e. The 

total methane emissions from Petroleum and Natural Gas 

Systems, based on the 2009 Inventory, adjusted for tight

sand plays and the Marcellus, is 328.29 MMtCO2e. Although 

this proposed rule does not include standards for 

 

11 U.S. EPA. Inventory of U.S. Greenhouse Gas Inventory and 

Sinks. 1990 - 2009. 

http://www.epa.gov/climatechange/emissions/downloads10/US-GHGInventory-2010_ExecutiveSummary.pdf
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regulating the GHG emissions discussed above, we continue 

to assess these significant emissions and evaluate 

appropriate actions for addressing these concerns. Because 

many of the proposed requirements for control of VOC 

emissions also control methane emissions as a co-benefit, 

the proposed VOC standards would also achieve significant 

reduction of methane emissions.

Significant emissions of oxides of nitrogen (NOx) also 

occur at oil and natural gas sites due to the combustion of 

natural gas in reciprocating engines and combustion 

turbines used to drive the compressors that move natural 

gas through the system, and from combustion of natural gas 

in heaters and boilers. While these engines, turbines, 

heaters and boilers are co-located with processes in the 

oil and natural gas sector, they are not in the Oil and 

Natural Gas source category and are not being addressed in 

this action. The NOx emissions from engines and turbines 

are covered by the Standards of Performance for Stationary 

Spark Internal Combustion Engines (40 CFR part 60, subpart 

JJJJ) and Standards of Performance for Stationary 

Combustion Turbines (40 CFR part 60, subpart KKKK), 

respectively.
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An additional source of NOx emissions would be pit 

flaring of VOC emissions from well completions during 

periods where REC is not feasible, as would be required 

under our proposed operational standards for wellhead 

affected facilities. As discussed below in section VI.B.4

(well completion), pit flaring is the only way we 

identified of controlling VOC emissions during these 

periods. Because there is no way of directly measuring the 

NOx produced, nor is there any way of applying controls 

other than minimizing flaring, we propose to allow flaring 

only when REC is not feasible. We have included our 

estimates of NOx formation from pit flaring in our 

discussion of secondary impacts in section VI.B.4.

3. What emission sources are being evaluated in this Oil 

and Natural Gas NSPS package?

The current NSPS only cover emissions of VOC and SO2

from one type of facility in the oil and natural gas 

sector, which is the natural gas processing plant. This is 

the only type of facility in the Oil and Natural Gas source 

category where we would expect SO2 to be emitted directly, 

although H2S contained in sour gas, when oxidized in the 

atmosphere or combusted in boilers and heaters in the 

field, forms SO2 as a product of oxidation. These field 
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boilers and heaters are not part of the Oil and Natural Gas 

source category and are generally too small to be regulated 

by the NSPS covering boilers (i.e., they have a heat input 

of less than 10 million British Thermal Units per hour). 

However, we may consider addressing them as part of a 

future sector-based strategy for the oil and natural gas 

sector. 

In addition to VOC emissions from gas processing 

plants, there are numerous sources of VOC throughout the 

oil and natural gas sector that are not addressed by the 

current NSPS. As explained above in section V.A, pursuant 

to CAA section 111(b), to the extent necessary, we are 

modifying the listed category to include all segments of 

the oil and natural gas industry for regulation. We are 

also proposing VOC standards to cover additional processes 

at oil and natural gas operations. These include NSPS for 

VOC from gas well completions, pneumatic controllers, 

compressors and storage vessels.

We believe that produced water ponds are also a 

potentially significant source of emissions, but we have 

only limited information. We, therefore, solicit comments 

on produced water ponds, particularly in the following 

subject areas:
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(a) We are requesting comments pertaining to methods 

for calculating emissions. The State of Colorado currently 

uses a mass balance that assumes 100 percent of the VOC 

content is emitted to the atmosphere. Water9, an air 

emissions model, is another option that has some 

limitations, including poor methanol estimation.

(b) We are requesting additional information on 

typical VOC content in produced water and any available 

chemical analyses, including data that could help clarify 

seasonal variations or differences among gas fields. 

Additionally, we request data that increase our 

understanding of how changing process variables or age of 

wells affect produced water output and VOC content.

(c) We solicit information on the size and throughput 

capacity of typical evaporation pond facilities and request 

suggestions on parameters that could be used to define 

affected facilities or affected sources. We also seek 

information on impacts of smaller evaporation pits that are 

co-located with drilling operations, whether those warrant 

control and, if so, how controls should be developed.

(d) An important factor is cost of emission reduction 

technologies, including recovery credits or cost savings 

realized from recovered salable product. We are seeking 
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information on these considerations as well.

(e) We are also seeking information on any limitations 

for emission reduction technologies such as availability of 

electricity, waste generation and disposal and throughput

and concentration constraints.

(f) Finally, we solicit information on separator 

technologies that are able to improve the oil-water 

separation efficiency.

4. What are the rationales for the proposed NSPS?

We have provided below our rationales for the proposed 

BSER determinations and performance standards for a number 

of VOC emission sources in the Oil and Natural Gas source 

category that are not covered by the existing NSPS. Our 

general process for evaluating systems of emission 

reduction for the emission sources discussed below 

included: (1) Identification of available control measures; 

(2) evaluation of these measures to determine emission 

reductions achieved, associated costs, nonair environmental 

impacts, energy impacts and any limitations to their 

application; and (3) selection of the control techniques 

that represent BSER based on the information we considered. 

We identified the control options discussed in this 

package through our review of relevant state and local 
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requirements and mitigation measures developed and reported 

by the EPA’s Natural Gas STAR program. The EPA’s Natural 

Gas STAR program has worked with industry partners since 

1993 to identify cost effective measures to reduce 

emissions of methane and other pollutants from natural gas 

operations. We relied heavily on this wealth of information 

in conducting this review. We also identified state 

regulations, primarily in Colorado and Wyoming, which 

require mitigation measures for some emission sources in 

the Oil and Natural Gas source category.

a. NSPS for Well Completions

Well completion activities are a significant source of 

VOC emissions, which occur when natural gas and non-methane 

hydrocarbons are vented to the atmosphere during flowback

of a hydraulically fractured gas well. Flowback emissions 

are short-term in nature and occur over a period of several 

days following fracturing of a new well or refracturing of 

an existing well. Well completions include multiple steps 

after the well bore hole has reached the target depth. 

These steps include inserting and cementing-in well casing, 

perforating the casing at one or more producing horizons, 

and often hydraulically fracturing one or more zones in the 

reservoir to stimulate production. Well recompletions may 
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also include hydraulic fracturing. Hydraulic fracturing is 

one technique for improving gas production where the 

reservoir rock is fractured with very high pressure fluid, 

typically water emulsion with a proppant (generally sand) 

that “props open” the fractures after fluid pressure is 

reduced. Emissions are a result of the backflow of the 

fracture fluids and reservoir gas at high volume and 

velocity necessary to lift excess proppant and fluids to 

the surface. This multi-phase mixture is often directed to 

a surface impoundment where natural gas and VOC vapors 

escape to the atmosphere during the collection of water, 

sand and hydrocarbon liquids. As the fracture fluids are 

depleted, the backflow eventually contains more volume of 

natural gas from the formation. Wells that are fractured 

generally have great amounts of emissions because of the 

extended length of the flowback period required to purge 

the well of the fluids and sand that are associated with 

the fracturing operation. Along with the fluids and sand 

from the fracturing operation, the 3 to 10-day flowback 

period also results in emissions of natural gas and VOC 

that would not occur in large quantities at oil wells or at 

natural gas wells that are not fractured. Thus, we estimate 

that gas well completions involving hydraulic fracturing 
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vent substantially more VOC, approximately 200 times more, 

than completions not involving hydraulic fracturing. 

Specifically, we estimate that uncontrolled well completion 

emissions for a hydraulically fractured gas well are 

approximately 23 tons of VOC, where emissions for a 

conventional gas well completion are around 0.12 tons VOC. 

These estimates are explained in detail in the TSD 

available in the docket. Based on our review, we believe 

that emissions from recompletions of previously completed 

wells that are fractured or refractured to stimulate 

production or to begin production from a new production 

horizon are of similar magnitude and composition as 

emissions from completions of new wells that have been 

hydraulically fractured. 

EPA has based the NSPS impacts analysis on best 

available emission data. However, we recognize that there 

is uncertainty associated with our estimates. For both new 

completions and recompletions, there are a variety of 

factors that will determine the length of the flowback 

period and actual volume of emissions such as the number of 

zones, depth, pressure of the reservoir, gas composition, 

etc. This variability means there will be some wells which 
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emit more than the estimated emission factor and some wells 

that emit less.

During our review, we examined information from the 

Natural Gas STAR program and the Colorado and Wyoming state 

rules covering well completions. We identified two 

subcategories of fractured gas wells: (1) Non-exploratory 

and non-delineation wells; and (2) exploratory and 

delineation wells. An exploratory well is the first well 

drilled to determine the presence of a producing reservoir 

and the well’s commercial viability. A delineation well is 

a well drilled to determine the boundary of a field or 

producing reservoir. Because exploratory and delineation 

wells are generally isolated from existing producing wells, 

there are no gathering lines available for collection of 

gas recovered during completion operations. In contrast, 

non-exploratory and non-delineation wells are located where 

existing, producing wells are connected to gathering lines 

and are, therefore, able to be connected to a gathering 

line to collect recovered salable natural gas product that 

would otherwise be vented to the atmosphere or combusted. 

For subcategory 1, we identified “green” completion, 

which we refer to as REC, as an option for reducing VOC 

emissions during well completions. REC are performed by 
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separating the flowback water, sand, hydrocarbon condensate 

and natural gas to reduce the portion of natural gas and 

VOC vented to the atmosphere, while maximizing recovery of 

salable natural gas and VOC condensate. In some cases, for 

a portion of the completion operation, such as when CO2 or 

nitrogen is injected with the fracture water, initial gas 

produced is not of suitable quality to introduce into the 

gathering line due to CO2 or nitrogen content or other 

undesirable characteristic. In such cases, for a portion of 

the flowback period, gas cannot be recovered, but must be 

either vented or combusted. In practice, REC are often 

combined with combustion to minimize the amount of gas and 

condensate being vented. This combustion process is rather 

crude, consisting of a horizontal pipe downstream of the 

REC equipment, fitted with a continuous ignition source and 

discharging over a pit near the wellhead. Because of the 

nature of the flowback (i.e., with periods of water, 

condensate, and gas in slug flow), conveying the entire 

portion of this stream to a traditional flare control 

device or other control device, such as a vapor recovery 

unit, is not feasible. These control devices are not 

designed to accommodate the multiphase flow consisting of 

water, sand and hydrocarbon liquids, along with the gas and 
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vapor being controlled. Although “pit flaring” does not 

employ a traditional flare control device, and is not 

capable of being tested or monitored for efficiency due to 

the multiphase slug flow and intermittent nature of the 

discharge of gas, water and sand over the pit, it does 

provide a means of minimizing vented gas and is preferable 

to venting. Because of the rather large exposed flame, open 

pit flaring can present a fire hazard or other undesirable 

impacts in some situations (e.g., dry, windy conditions, 

proximity to residences, etc.). As a result, we are aware 

that owners and operators may not be able to pit flare 

unrecoverable gas safely in every case. In some cases, pit 

flaring may be prohibited by local ordinance. 

Equipment required to conduct REC may include tankage, 

special gas-liquid-sand separator traps and gas 

dehydration. Equipment costs associated with REC will vary 

from well to well. Typical well completions last between 3 

and 10 days and costs of performing REC are projected to be 

between $700 and $6,500 per day, including a cost of 

approximately $3,523 per completion event for the pit 

flaring equipment. However, there are savings associated 

with the use of REC because the gas recovered can be 

incorporated into the production stream and sold. In fact, 
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we estimate that REC will result in an overall net cost 

savings in many cases.

The emission reductions for a hydraulically fractured 

well are estimated to be around 22 tons of VOC. Based on an 

average incremental cost of $33,237 per completion, the 

cost effectiveness of REC, without considering any cost 

savings, is around $1,516 per ton of VOC (which we have 

previously found to be cost effective on average). When the 

value of the gas recovered (approximately 150 tons of 

methane per completion) is considered, the cost

effectiveness is estimated as an average net savings of $99

per ton VOC reduced, using standard discount rates. We 

believe that these costs are very reasonable, given the 

emission reduction that would be achieved. Aside from the 

potential hazards associated with pit flaring, in some 

cases, we did not identify any nonair environmental 

impacts, health or energy impacts associated with REC 

combined with combustion. However, pit flaring would 

produce NOx emissions. Because we believe that these 

emissions cannot be controlled or measured directly due to 

the open combustion process characteristic of pit flaring, 

we used published emission factors (EPA Emission Guidelines 

AP-42)to estimate the NOx emissions for purposes of 
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assessing secondary impacts. For category 1 well 

completions, we estimated that 0.02 tons of NOx are produced 

per event. This is based on the assumption that 5 percent 

of the flowback gas is combusted by the combustion device. 

The 1.2 tons of VOC controlled during the pit flaring 

portion of category 1 well completions is approximately 57 

times greater than the NOx produced by pit flaring. Thus, 

we believe that the benefit of the VOC reduction far 

outweighs the secondary impact of NOx formation during pit 

flaring.

We believe that, based on the analysis above, REC in 

combination with combustion is BSER for subcategory 1 

wells. We considered setting a numerical performance 

standard for subcategory 1 wells. However, it is not 

practicable to measure the emissions during pit flaring or 

venting because the gas is discharged over the pit along 

with water and sand in multiphase slug flow. Therefore, we 

believe it is not feasible to set a numerical performance 

standard. Pursuant to section 111(h)(2) of the CAA, we are 

proposing an operational standard for subcategory 1 wells 

that would require a combination of REC and pit flaring to 

minimize venting of gas and condensate vapors to the 

atmosphere, with provisions for venting in lieu of pit 
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flaring for situations in which pit flaring would present 

safety hazards or for periods when the flowback gas is 

noncombustible due to high concentrations of nitrogen or 

CO2. The proposed operational standard would be accompanied 

by requirements for documentation of the overall duration

of the completion event, duration of recovery using REC, 

duration of combustion, duration of venting, and specific 

reasons for venting in lieu of combustion.

We recognize that there is heterogeneity in well 

operations and costs, and that while RECs may be costeffective on average, they may not be for all operators.

Nonetheless, EPA is proposing to require an operational 

standard rather than a performance-based standard (e.g., 

requiring that some percentage of emissions be flared or 

captured), because we believe there are no feasible ways 

for operators to measure emissions with enough certainty to 

demonstrate compliance with a performance-based standard 

for REC in combination with pit flaring. The EPA requests 

comment on this and seeks input on whether alternative 

approaches to requiring REC for all operators with access 

to pipelines may exist that would allow operators to meet a 

performance-based standard if they can demonstrate that an 

REC is not cost effective. 
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We have discussed above certain situations where 

unrecoverable gas would be vented because pit flaring would 

present a fire hazard or is infeasible because gas is 

noncombustible due to high concentrations of nitrogen or 

CO2. We solicit comment on whether there are other such 

situations where flaring would be unsafe or infeasible, and 

potential criteria that would support venting in lieu of 

pit flaring. In addition, we learned that coalbed methane 

reservoirs may have low pressure, which would present a 

technical barrier for performing a REC because the well 

pressure may not be substantial enough to overcome 

gathering line pressure. In addition, we identified that 

coalbed methane wells often have low to almost no VOC 

emissions, even following the hydraulic fracturing process. 

We solicit comment on criteria and thresholds that could be 

used to exempt some well completion operations occurring in 

coalbed methane reservoirs from the requirements for 

subcategory 1 wells.

Of the 25,000 new and modified fractured gas wells 

completed each year, we estimate that approximately 3,000 

to 4,000 currently employ reduced emission completion. We 

expect this number to increase to over 21,000 REC annually 

as operators comply with the proposed NSPS. We estimate 
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that approximately 9,300 new wells and 12,000 existing 

wells will be fractured or refractured annually that would 

be subject to subcategory 1 requirements under the NSPS. We 

believe that there will be a sufficient supply of REC 

equipment available by the time the NSPS becomes effective. 

However, energy availability could be affected if a 

shortage of REC equipment was allowed to cause delays in 

well completions. We request comment on whether sufficient 

supply of this equipment and personnel to operate it will 

be available to accommodate the increased number of REC by 

the effective date of the NSPS. We also request specific 

estimates of how much time would be required to get enough 

equipment in operation to accommodate the full number of 

REC performed annually. 

In the event that public comments indicate that 

available equipment would likely be insufficient to 

accommodate the increase in number of REC performed, we are 

considering phasing in requirements for well completions 

that would achieve an overall comparable level of 

environmental benefit. For example, operators performing 

completions of fractured or refractured existing wells 

(i.e., modified wells) could be allowed to control 

emissions through pit flaring instead of REC for some 
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period of time. After some date certain, all modified wells 

would be subject to REC. We solicit comment on the phasing 

of requirements for REC along with suggestions for other 

ways to address a potential short-term REC equipment 

shortage that may hinder operators’ compliance with the 

proposed NSPS, while also achieving a comparable level of 

reduced emissions to the air.

Although we have determined that, on average, reduced 

emission completions are cost effective, well and reservoir 

characteristics could vary, such that some REC are more 

cost effective than others. Unlike most stationary source 

controls, REC equipment is used only for a 3 to 10 day 

period. Our review found that most operators contract with 

service companies to perform REC rather than purchase the 

equipment themselves, which was reflected in our economic 

analysis. It is also possible that the contracting costs of 

supplying and operating REC equipment may rise in the short 

term with the increased demand for those services. We 

request comment and any available technical information to 

judge whether our assumption of $33,237 per well completion 

for this service given the projected number of wells in 

2015 subject to this requirement is accurate.

We believe that the proposed rule regulates only 
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significant emission sources for which controls are costeffective. Nevertheless, we solicit comment and supporting 

data on appropriate thresholds (e.g., pressure, flowrate) 

that we should consider in specifying which well 

completions are subject to the REC requirements for 

subcategory 1 wells. Comments specifying thresholds should 

include an analysis of why sources below these thresholds 

are not cost effective to control.

In addition, there may be economic, technical or other 

opportunities or barriers associated with performing cost 

effective REC that we have not identified in our review. 

For example, some small regulated entities may have an 

increased source of revenue due to the captured product. On 

the other hand, some small regulated entities may have less 

access to REC than larger regulated entities might have. We 

request information on such opportunities and barriers that 

we should consider and suggestions for how we may take them 

into account in structuring the NSPS.

The second subcategory of fractured gas wells includes 

exploratory wells or delineation wells. Because these types 

of wells generally are not in proximity to existing 

gathering lines, REC is not an option, since there is no 

infrastructure in place to get the recovered gas to market 
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or further processing. For these wells, the only potential 

control option we were able to identify is pit flaring,

described above. As explained above, because of the slug 

flow nature of the flowback gas, water and sand, control by 

a traditional flare control device or other control 

devices, such as vapor recovery units, is infeasible, which 

leaves pit flaring as the only practicable control system 

for subcategory 2 wells. As also discussed above, open pit 

flaring can present a fire hazard or other undesirable 

impacts in some situations. Aside from the potential 

hazards associated with pit flaring, in some cases, we did 

not identify any nonair environmental impacts, health or 

energy impacts associated with pit flaring. However, pit 

flaring would produce NOx emissions. As in the case of 

category 1 wells, we believe that these emissions cannot be

controlled or measured directly due to the open combustion 

process characteristic of pit flaring. We again used 

published emission factors to estimate the NOx emissions 

for purposes of assessing secondary impacts. For category 2 

well completions, we estimated that 0.32 tons of NOx are 

produced as secondary emissions per completion event. This 

is based on the assumption that 95 percent of flowback gas 

is combusted by the combustion device. The 22 tons of VOC 
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reduced during the pit flaring used to control category 2 

well completions is approximately 69 times greater than the 

NOx produced. Thus, we believe that the benefit of the VOC 

reduction far outweighs the secondary impact of NOx

formation during pit flaring.

In light of the above, we propose to determine that 

BSER for subcategory 2 wells would be pit flaring. As we 

explained above, it is not practicable to measure the 

emissions during pit flaring or venting because the gas is 

discharged during flowback mixed with water and sand in 

multiphase slug flow. It is, therefore, not feasible to set 

a numerical performance standard.

Pursuant to CAA section 111(h)(2), we are proposing an 

operational standard for subcategory 2 wells that requires 

minimization of venting of gas and hydrocarbon vapors 

during the completion operation through the use of pit 

flaring, with provisions for venting in lieu of pit flaring

for situations in which flaring would present safety 

hazards or for periods when the flowback gas is 

noncombustible due to high concentrations of nitrogen or 

carbon dioxide. 

Consistent with requirements for subcategory 1 wells, 

owners or operators of subcategory 2 wells would be 
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required to document completions and provide justification 

for periods when gas was vented in lieu of combustion. We 

solicit comment on whether there are other such situations 

where flaring would be unsafe or infeasible and potential 

criteria that would support venting in lieu of pit flaring.

For controlling completion emissions at oil wells and 

conventional (non-fractured) gas wells, we have identified 

and evaluated the following control options: REC in 

conjunction with pit flaring and pit flaring alone. Due to 

the low uncontrolled VOC emissions of approximately 0.007 

ton per completion and, therefore, low potential emission 

reductions from these events, the cost per ton of reduction 

based on REC would be extremely high (over $700,000 per ton 

of VOC reduced). We evaluated the use of pit flaring alone 

as a system for controlling emissions from oil wells and 

conventional gas wells and determined that the cost costeffectiveness would be approximately $520,000 per ton for 

oil wells and approximately $32,000 per ton for

conventional gas wells. In light of the high cost per ton 

of VOC reduction, we do not consider either of these 

control options to be BSER for oil wells and conventional 

wells.
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We propose that fracturing (or refracturing) and 

completion of an existing well (i.e., a well existing prior 

to (INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER)) is 

considered a modification under CAA section 111(a), because 

physical change occurs to the existing well, which includes 

the wellbore, casing and tubing, resulting in an emissions 

increase during the completion operation. The physical 

change, in this case, would be caused by the reperforation 

of the casing and tubing, along with the refracturing of 

the wellbore. The increased VOC emissions would occur 

during the flowback period following the fracturing or 

refracturing operation. Therefore, the proposed standards 

for category 1 and category 2 wells would apply to 

completions at existing fractured or refractured wells.

EPA seeks comment on the 10 percent per year rate of 

refracturing for natural gas wells assumed in the impacts 

analysis found in the TSD. EPA has received anecdotal 

information suggesting that refracturing could be occurring 

much less frequently, while others suggest that the percent 

of wells refractured in a given year could be greater. We

seek comment and comprehensive data and information on the 

rate of refracturing and key factors that influence or 

determine refracturing frequency.
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In addition to well completions, we considered VOC 

emissions occurring at the wellhead affected facility 

during subsequent day-to-day operations during well 

production. As discussed below in section VI.B.1.e, VOC 

emissions from wellheads are very small during production 

and account for about 2.6 tons VOC per year. We are not 

aware of any cost effective controls that can be used to 

address these relatively small emissions.

b. NSPS for Pneumatic Controllers

Pneumatic controllers are automated instruments used 

for maintaining a process condition, such as liquid level, 

pressure, pressure differential and temperature. Pneumatic 

controllers are widely used in the oil and natural gas 

sector. In many situations across all segments of the oil 

and gas industry, pneumatic controllers make use of the 

available high-pressure natural gas to operate. In these 

“gas-driven” pneumatic controllers, natural gas may be 

released with every valve movement or continuously from the 

valve control pilot. The rate at which this release occurs 

is referred to as the device bleed rate. Bleed rates are 

dependent on the design of the device. Similar designs will 

have similar steady-state rates when operated under similar 

conditions. Gas-driven pneumatic controllers are typically 
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characterized as “high-bleed” or “low-bleed,” where a highbleed device releases more than 6 standard cubic feet per 

hour (scfh) of gas, with 18 scfh bleed rate being what we 

used in our analyses below. There are three basic designs: 

(1) Continuous bleed devices (high or low-bleed) are used

to modulate flow, liquid level or pressure and gas is 

vented at a steady-state rate; (2) actuating/intermittent 

devices (high or low-bleed) perform quick control movements 

and only release gas when they open or close a valve or as 

they throttle the gas flow; and (3) self-contained devices 

release gas to a downstream pipeline instead of to the 

atmosphere. We are not aware of any add-on controls that 

are or can be used to reduce VOC emissions from gas-driven 

pneumatic devices.

For an average high-bleed pneumatic controller located 

in production (where the content of VOC in the raw product 

stream is relatively high), the difference in VOC emissions 

between a high-bleed controller and a low-bleed controller 

is around 1.8 tpy. For the transmission and storage segment 

(where the content of VOC in the pipeline quality gas is 

relatively low), the difference in VOC emissions between a 

high-bleed controller and a low-bleed controller is around 

0.89 tpy. We have developed projections that estimate that 
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approximately 13,600 new gas-driven units in the production 

segment and 67 new gas-driven units in the transmission and 

storage segment will be installed each year, including 

replacement of old units. Not all pneumatic controllers are 

gas driven. These “non-gas driven” pneumatic controllers 

use sources of power other than pressurized natural gas, 

such as compressed “instrument air.” Because these devices 

are not gas driven, they do not release natural gas or VOC 

emissions, but they do have energy impacts because 

electrical power is required to drive the instrument air 

compressor system. Electrical service of at least 13.3 

kilowatts (kW) is required to power a 10 horsepower (hp)

instrument air compressor, which is a relatively small 

capacity compressor. At sites without available electrical 

service sufficient to power an instrument air compressor,

only gas driven pneumatic devices can be used. During our 

review, we determined that gas processing plants are the 

only facilities in the oil and natural gas sector highly 

likely to have electrical service sufficient to power an 

instrument air system, and that approximately half of 

existing gas processing plants are using non-gas driven 

devices. 
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For devices at gas processing plants, we evaluated the 

use of non-gas driven controllers and low-bleed controllers 

as options for reducing VOC emissions, with high-bleed 

controllers being the baseline. As mentioned above, non-gas 

driven devices themselves have zero emissions, but they do 

have energy impacts because electrical power is required to 

drive the instrument air compressor system. In our cost 

analysis, we determined that the annualized cost of 

installing and operating a fully redundant 10 hp (13.3 kW) 

instrument air system (systems generally are designed with 

redundancy to allow for system maintenance and failure 

without loss of air pressure), including duplicate 

compressors, air tanks and dryers, would be $11,090. A 

system of this size is capable of serving 15 control loops 

and reducing VOC emissions by 4.2 tpy, for a cost 

effectiveness of $2,659 per ton of VOC reduced. If the 

savings of the salable natural gas that would have been 

emitted is considered, the value of the gas not emitted 

would help offset the cost for this control, bringing the 

cost per ton of VOC down to $1,824.

We also evaluated the use of low-bleed controllers in 

place of high-bleed controllers at processing plants. We 

evaluated the impact of bleeding 6 standard cubic feet of 
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natural gas per hour, which is the maximum bleed rate from 

low-bleed controllers, according to manufacturers of these 

devices. We chose natural gas as a surrogate for VOC, 

because manufacturers’ technical specifications for 

pneumatic controllers are stated in terms of natural gas 

bleed rate rather than VOC. The capital cost difference 

between a new high-bleed controller and a new low-bleed 

controller is estimated to be $165. Without taking into 

account the savings due to the natural gas losses avoided, 

the annual costs are estimated to be around $23 per year, 

which is a cost of $13 per ton of VOC reduced for the 

production segment. If the savings of the salable natural 

gas that would have been emitted is considered, there is a 

net savings of $1,519 per ton of VOC reduced.

Although the non-gas-driven controller system is more 

expensive than the low-bleed controller system, it is still 

reasonably cost-effective. Furthermore, the non-gas-driven 

controller system achieves a 100-percent VOC reduction in 

contrast to a 66-percent reduction achieved by a low-bleed 

controller. Moreover, we believe the collateral emissions 

from electrical power generation needed to run the 

compressor are very low. Finally, non-gas-driven pneumatic 

controllers avoid potentially explosive concentrations of 
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natural gas which can occur as a result of normal bleeding 

from groups of gas-driven pneumatic controllers located in 

close proximity, as they often are at gas processing 

plants. Based on our review described above, we believe 

that a non-gas-driven controller is BSER for reducing VOC 

emissions from pneumatic devices at gas processing plants. 

Accordingly, the proposed standard for pneumatic devices at 

gas processing plants is a zero VOC emission limit.

For the production (other than processing plants) and 

transmission and storage segments, where electrical service 

sufficient to power an instrument air system is likely 

unavailable and, therefore, only gas-driven devices can be 

used, we evaluated the use of low-bleed controllers in 

place of high-bleed controllers. Just as in our analysis of 

low-bleed controllers as an option for gas processing 

plants, we evaluated the impact of bleeding 6 standard 

cubic feet per minute (scfm) of natural gas per hour 

contrasted with 18 scfm from a high-bleed unit. Again, the 

capital cost difference between a new high-bleed controller 

and a new low-bleed controller is estimated to be $165. 

Without taking into account the savings due to the natural 

gas losses avoided, the annual costs are estimated to be 

around $23 per year, which is a cost of $13 per ton of VOC
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reduced for the production segment. If the savings of the 

salable natural gas that would have been emitted is 

considered, there is a net savings for this control. In the 

transmission and storage segment, where the VOC content of 

the vented gas is much lower than in the production 

segment, the cost effectiveness of a low-bleed pneumatic 

device is estimated to be around $262 per ton of VOC 

reduced. However, there are no potential offsetting savings 

to be realized in the transmission and storage segment, 

since the operators of transmission and storage stations 

typically do not own the gas they are handling. Based on 

our evaluation of the emissions and costs, we believe that 

low-bleed controllers represent BSER for pneumatic 

controllers in the production (other than processing 

plants) and transmission and storage segments. Therefore, 

for pneumatic devices at these locations, we propose a 

natural gas bleed rate limit of 6.0 scfh to reflect the VOC 

limit with the use of a low-bleed controller.

There may be situations where high-bleed controllers

and the attendant gas bleed rate greater than 6 cubic feet 

per hour, are necessary due to functional requirements, 

such as positive actuation or rapid actuation. An example 

would be controllers used on large emergency shutdown 
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valves on pipelines entering or exiting compression 

stations. For such situations, we have provided in the 

proposed rule an exemption where pneumatic controllers 

meeting the emission standards discussed above would pose a 

functional limitation due to their actuation response time 

or other operating characteristics. We are requesting 

comments on whether there are other situations that should 

be considered for this exemption. If you provide such 

comment, please specify the criteria for such situations

that would help assure that only appropriate exemptions are 

claimed.

The proposed standards would apply to installation of 

a new pneumatic device (including replacing an existing 

device with a new device). We consider that a pneumatic 

device, an apparatus, is an affected facility and each 

installation is construction subject to the proposed NSPS. 

See definitions of “affected facility” and “construction” 

at 40 CFR 60.2. 

c. NSPS for Compressors

There are many locations throughout the oil and 

natural gas sector where compression of natural gas is 

required to move it along the pipeline. This is 

accomplished by compressors powered by combustion turbines, 
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reciprocating internal combustion engines or electric 

motors. Turbine-powered compressors use a small portion of 

the natural gas that they compress to fuel the turbine. The 

turbine operates a centrifugal compressor, which compresses 

the natural gas for transit through the pipeline. Sometimes 

an electric motor is used to turn a centrifugal compressor. 

This type of compressor does not require the use of any of 

the natural gas from the pipeline, but it does require a 

substantial source of electricity. Reciprocating spark 

ignition engines are also used to power many compressors, 

referred to as reciprocating compressors, since they 

compress gas using pistons that are driven by the engine. 

Like combustion turbines, these engines are fueled by 

natural gas from the pipeline. Both centrifugal and 

reciprocating compressors are sources of VOC emissions and 

were evaluated for coverage under the NSPS.

Centrifugal Compressors. Centrifugal compressors 

require seals around the rotating shaft to minimize gas

leakage and fugitive VOC emissions from where the shaft 

exits the compressor casing. There are two types of seal 

systems: Wet seal systems and mechanical dry seal systems. 

Wet seal systems use oil, which is circulated under 

high pressure between three or more rings around the 
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compressor shaft, forming a barrier to minimize compressed 

gas leakage. Very little gas escapes through the oil 

barrier, but considerable gas is absorbed by the oil. The 

amount of gas absorbed and entrained by the oil barrier is 

affected by the operating pressure of the gas being 

handled; higher operating pressures result in higher 

absorption of gas into the oil. Seal oil is purged of the 

absorbed and entrained gas (using heaters, flash tanks and 

degassing techniques) and recirculated to the seal area for 

reuse. Gas that is purged from the seal oil is commonly 

vented to the atmosphere. Degassing of the seal oil emits 

an average of 47.7 scfm of gas, depending on the operating 

pressure of the compressor. An uncontrolled wet seal system 

can emit, on average, approximately 20.5 tpy of VOC during 

the venting process (production segment) or about 3.5 tpy 

(transmission and storage segment). We identified two 

potential control techniques for reducing emissions from 

degassing of wet seal systems: (1) Routing the gas back to 

a low pressure fuel stream to be combusted as fuel gas and 

(2) routing the gas to a flare. We know only of anecdotal, 

undocumented information on routing of the gas back to a 

fuel stream and, therefore, were unable to assess costs and 

cost effectiveness of the first option. Although we do not 
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have specific examples of routing emissions from wet seal 

degassing to a flare, we were able to estimate the cost, 

emission reductions and cost effectiveness of the second 

option using uncontrolled wet seals as a baseline. 

Based on the average uncontrolled emissions of wet 

seal systems discussed above and a flare efficiency of 95 

percent, we determined that VOC emission reductions from a 

wet seal system would be an average of 19.5 tpy (production 

segment) or 3.3 tpy (transmission and storage segment). 

Using an annualized cost of flare installation and 

operation of $103,373, we estimated the incremental cost 

effectiveness of this option (from uncontrolled wet seals 

to controlled wet seals using a flare) to be approximately 

$5,300/ton and $31,000/ton for the production segment and 

transmission and storage segment, respectively. With this 

option, there would be secondary air impacts from 

combustion. However we did not identify any nonair quality 

or energy impacts associated with this control technique. 

Dry seal systems do not use any circulating seal oil. 

Dry seals operate mechanically under the opposing force 

created by hydrodynamic grooves and springs. Fugitive 

emissions occur from dry seals around the compressor shaft. 

Based on manufacturer studies and engineering design 
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estimates, fugitive emissions from dry seal systems are 

approximately 6 scfm of gas, depending on the operating 

pressure of the compressor. A dry seal system can have 

fugitive emissions of, on average, approximately 2.6 tpy of 

VOC (production segment) or about 0.4 tpy (transmission and 

storage segment). We did not identify any control device 

suitable to capture and control the fugitive emissions from 

dry seals around the compressor shaft.

Using uncontrolled wet seals as a baseline, we 

evaluated the reductions and incremental cost effectiveness 

of dry seal systems. Based on the average fugitive 

emissions, we determined that VOC emission reductions 

achieved by dry seal systems compared to uncontrolled wet 

seal systems would be 18 tpy (production segment) and 3.1 

tpy (transmission and storage segment). Combined with an 

annualized cost of dry seal systems of $10,678, the 

incremental cost effectiveness compared to uncontrolled wet

seal systems would be $595/ton and $3,495/ton for the 

production segment and transmission and storage segment, 

respectively. We identified neither nonair quality nor any 

energy impacts associated with this option.

In performing our analysis, we estimated the 

incremental cost of a dry seal compressor over that of an 
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equivalent wet seal compressor to be $75,000. This value 

was obtained from a vendor who represents a large share of 

the market for centrifugal compressors. However, this 

number likely represents a conservatively high value 

because wet seal units have a significant amount of 

ancillary equipment, namely the seal oil system and, thus,

additional capital expenses. Dry seal systems have some 

ancillary equipment (the seal gas filtration system), but 

the costs are less than the wet seal oil system. We were

not able to directly confirm this assumption with the 

vendor, however, a search of product literature showed that 

seal oil systems and seal gas filtration systems are 

typically listed separate from the basic compressor 

package. Using available data on the cost of this 

equipment, it is very likely that the cost of purchasing a 

dry seal compressor may actually be lower that a wet seal 

compressor. We seek comment on available cost data of a dry 

seal versus wet seal compressor, including all ancillary 

equipment costs.

In light of the above analyses, we propose to 

determine that dry seal systems are BSER for reducing VOC 

emissions from centrifugal compressors. We evaluated the 

possibility of setting a performance standard that reflects 
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the emission limitation achievable through the use of a dry 

seal system. However, as mentioned above, VOC from 

centrifugal compressors with dry seals are fugitive 

emissions from around the compressor shafts. There is no 

device to capture and control these fugitive emissions, nor 

can reliable measurement of these emissions be conducted 

due to difficulty in accessing the leakage area and danger 

of contacting the shaft rotating at approximately 30,000 

revolutions per minute. This not only poses a likely hazard 

that would destroy test equipment on contact, it poses a 

safety hazard to personnel, as well. Therefore, pursuant to 

section 111(h)(2) of the CAA, we are proposing an equipment 

standard that would require the use of dry seals to limit 

the VOC emissions from new centrifugal compressors. We 

consider that a centrifugal compressor, an apparatus, is an 

affected facility and each installation is construction 

subject to the proposed NSPS. See definitions of “affected 

facility” and “construction” at 40 CFR 60.2. Accordingly, 

the proposed standard would apply to installation of new 

centrifugal compressors at new locations, as well as 

replacement of old compressors. 

Although we are proposing to determine dry seal 

systems to be BSER for centrifugal compressors, we are 
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soliciting comments on the emission reduction potential, 

cost and any limitations for the option of routing the gas 

back to a low pressure fuel stream to be combusted as fuel 

gas. In addition, we solicit comments on whether there are 

situations or applications where wet seal is the only 

option, because a dry seal system is infeasible or 

otherwise inappropriate. 

Reciprocating Compressors. Reciprocating compressors 

in the natural gas industry leak natural gas fugitive VOC 

during normal operation. The highest volumes of gas loss 

and fugitive VOC emissions are associated with piston rod 

packing systems. Packing systems are used to maintain a 

tight seal around the piston rod, preventing the high 

pressure gas in the compressor cylinder from leaking, while 

allowing the rod to move freely. This leakage rate is 

dependent on a variety of factors, including physical size 

of the compressor piston rod, operating speed and operating 

pressure. Under the best conditions, new packing systems 

properly installed on a smooth, well-aligned shaft can be 

expected to leak a minimum of 11.5 scfh. Higher leak rates 

are a consequence of fit, alignment of the packing parts

and wear. 

We evaluated the possibility of reducing VOC emissions 
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from reciprocal compressors through a control device. 

However, VOC from reciprocating compressors are fugitive 

emissions from around the compressor shafts. Although it is 

possible to construct an enclosure around the rod packing 

area and vent the emissions outside for safety purposes, 

connection to a closed vent system and control device would 

create back pressure on the leaking gas. This back pressure 

would cause the leaked gas instead to be forced inside the 

crankcase of the engine, which would dilute lubricating 

oil, causing premature failure of engine bearings, pose an 

explosion hazard and eventually be vented from the 

crankcase breather, defeating the purpose of a control 

device. 

As mentioned above, as packing wears and deteriorates, 

leak rates can increase. We, therefore, evaluate 

replacement of compressor rod packing systems as an option 

for reducing VOC emissions. Conventional bronze-metallic 

packing rings wear out and need to be replaced every 3 to 5

years, depending on the compressor’s rate of usage (i.e., 

the percentage of time that a compressor is in pressurized 

mode). 

Based on industry experience in the Natural Gas STAR 

program and other sources, we evaluated the rod packing 
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replacement costs for reciprocating compressors at 

different segments of this industry. Usage rates vary by 

segment. Usage rates for compressors at wellheads, 

gathering/boosting stations, processing plants, 

transmission stations and storage facilities are 100, 79, 

90, 79 and 68 percent, respectively. Reciprocating 

compressors at wellheads are small and operate at lower 

pressures, which limit VOC emissions from these sources. 

Due to the low VOC emissions from these compressors, about 

0.044 tpy, combined with an annual cost of approximately 

$3,700, the cost per ton of VOC reduction is rather high. 

We estimated that the cost effectiveness of controlling 

wellhead compressors is over $84,000 per ton of VOC 

reduced, which we believe to be too high and, therefore,

not reasonable. Because the cost effectiveness of replacing 

packing wellhead compressor rod systems is not reasonable, 

and absent other emission reduction measures, we did not 

find a BSER for reducing VOC emissions from reciprocal 

compressors at wellheads. 

For reciprocating compressors located at other oil and 

gas operations, we estimated that the cost effectiveness of 

controlling compressor VOC emissions by rod packing 

replacement would be $870 per ton of VOC for reciprocating 
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compressors at gathering and boosting stations, $270 per 

ton of VOC for reciprocating compressors at processing 

stations, $2,800 per ton of VOC for reciprocating 

compressors at transmission stations and $3,700 per ton of 

VOC for reciprocating compressors at underground storage 

facilities. We consider these costs to be reasonable. We 

did not identify any nonair quality health or environmental 

impacts or energy impacts associated with rod packing 

replacement. In light of the above, we propose to determine 

that such control is the BSER for reducing VOC emission 

from compressors at these other oil and gas operations. 

Because VOC emitted from reciprocal compressors are 

fugitive emissions, there is no device to capture and 

control the emissions. Therefore, pursuant to section 

111(h) of the CAA, we are proposing an operational 

standard. Based on industry experience reported to the 

Natural Gas STAR program, we determined that packing rods 

should be replaced every 3 years of operation. However, to 

account for segments of the industry in which reciprocating 

compressors operate in pressurized mode a fraction of the 

calendar year (ranging from approximately 68 percent up to 

approximately 90 percent), the proposed rule expresses the 

replacement requirement in terms of hours of operation 
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rather than on a calendar year basis. One year of 

continuous operation would be 8,760 hours. Three years of 

continuous operation would be 26,280 hours, or rounded to 

the nearest thousand, 26,000 hours. Accordingly, the 

proposed rule would require the replacement of the rod 

packing every 26,000 hours of operation. The owner or 

operator would be required to monitor the hours of 

operation beginning with the installation of the 

reciprocating compressor affected facility. Cumulative 

hours of operation would be reported each year in the 

facility’s annual report. Once the hours of operation 

reached 26,000 hours, the owner or operator would be 

required to change the rod packing immediately, although 

unexpected shutdowns could be avoided by tracking hours of 

operation and planning for packing replacement at scheduled 

maintenance shutdowns before the hours of operation reached 

26,000. 

Some industry partners of the Natural Gas STAR program 

currently conduct periodic testing to determine the leakage 

rates that would identify economically beneficial 

replacement of rod packing based on natural gas savings. 

Therefore, we are soliciting comments on incorporating a 

method similar to that in the Natural Gas STAR’s Lessons 
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Learned document entitled, Reducing Methane Emissions from 

Compressor Rod Packing Systems

(http://www.epa.gov/gasstar/documents/ll_rodpack.pdf), to 

be incorporated in the NSPS. We are soliciting comments on 

how to determine a suitable leak threshold above which rod 

packing replacement would be cost effective for VOC 

emission reduction. We are also soliciting comment on the 

appropriate replacement frequency and other considerations 

that would be associated with regular replacement periods.

d. NSPS for Storage Vessels

Crude oil, condensate and produced water are typically 

stored in fixed-roof storage vessels. Some vessels used for 

storing produced water may be open-top tanks. These 

vessels, which are operated at or near atmospheric pressure 

conditions, are typically located as part of a tank 

battery. A tank battery refers to the collection of process 

equipment used to separate, treat and store crude oil, 

condensate, natural gas and produced water. The extracted 

products from productions wells enter the tank battery 

through the production header, which may collect product 

from many wells.

Emissions from storage vessels are a result of 

working, breathing and flash losses. Working losses occur 
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due to the emptying and filling of storage tanks. Breathing 

losses are the release of gas associated with daily 

temperature fluctuations and other equilibrium effects. 

Flash losses occur when a liquid with dissolved gases is 

transferred from a vessel with higher pressure to a vessel 

with lower pressure, thus, allowing dissolved gases and a 

portion of the liquid to vaporize or flash. In the oil and 

natural gas production segment, flashing losses occur when 

live crude oils or condensates flow into a storage tank 

from a processing vessel operated at a higher pressure. 

Typically, the larger the pressure drop, the more flash 

emissions will occur in the storage stage. Temperature of 

the liquid also influences the amount of flash emissions. 

The amount of liquid entering the tank during a given time, 

commonly known as throughput, also affects the emission 

rate, with higher throughput tanks having higher annual 

emissions, given that other parameters are the same.

In analyzing controls for storage vessels, we reviewed 

control techniques identified in the Natural Gas STAR 

program and state regulations. We identified two ways of 

controlling storage vessel emissions, both of which can 

reduce VOC emissions by 95 percent. One option would be to 

install a vapor recovery unit (VRU) and recover all the 
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vapors from the tanks. The other option would be to route 

the emissions from the tanks to a flare control device. 

These devices could be “candlestick” flares that are found 

at gas processing plants or other larger facilities or 

enclosed combustors which are commonly found at smaller 

field facilities. We estimated the total annual cost for a 

VRU to be approximately $18,900/yr and for a flare to be 

approximately $8,900/yr. Cost effectiveness of these 

control options depend on the amount of vapor produced by 

the storage vessels being controlled. A VRU has a potential 

advantage over flaring, in that it recovers hydrocarbon 

vapors that potentially can be used as supplemental burner 

fuel, or the vapors can be condensed and collected as 

condensate that can be sold. If natural gas is recovered, 

it can be sold, as well, as long as a gathering line is 

available to convey the recovered salable gas product to 

market or to further processing. A VRU also does not have 

secondary air impacts that flaring does, as described 

below. However, a VRU cannot be used in all instances. Some 

conditions that affect the feasibility of VRU are: 

Availability of electrical service sufficient to power the 

VRU; fluctuations in vapor loading caused by surges in 

throughput and flash emissions from the tank; potential for 
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drawing air into condensate tanks causing an explosion 

hazard; and lack of appropriate destination or use for the 

vapor recovered. 

Like a VRU, a flare control device can also achieve a 

control efficiency of 95 percent. There are no technical 

limitations on the use of flares to control vapors from 

condensate and crude oil tanks. However, flaring has a 

secondary impact from emissions of NOx and other 

pollutants. In light of the technical limitations with the 

use of a VRU, we are unable to conclude that a VRU is 

better than flaring. We, therefore, propose to determine 

that both a VRU and flare are BSER for reducing VOC 

emission from storage vessels. We propose an NSPS of 95-

percent reduction for storage vessels to reflect the level 

of emission reduction achievable by VRU and flares. 

VOC emissions from storage vessels vary significantly, 

depending on the rate of liquid entering and passing 

through the vessel (i.e., its throughput), the pressure of 

the liquid as it enters the atmospheric pressure storage 

vessel, the liquid’s volatility and temperature of the 

liquid. Some storage vessels have negligible emissions, 

such as those with very little throughput and/or handling 

heavy liquids entering at atmospheric pressure. We do not 
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believe that it is cost effective to control these vessels. 

We believe it is important to control tanks with 

significant VOC emissions under the proposed NSPS. 

In our analysis, we evaluated storage tanks with 

varying condensate or crude oil throughput. We used

emission factors developed for the Texas Environmental 

Research Consortium in a study that evaluated VOC emissions 

from crude oil and condensate storage tanks by performing 

direct measurements. The study found that the average VOC 

emission factor for crude oil storage tanks was 1.6 pounds 

(lb) VOC per barrel of crude oil throughput. The average 

VOC emission factor for condensate tanks was determined to 

be 33.3 lb VOC per barrel of condensate throughput. 

Applying these emission factors and evaluating condensate 

throughput rates of 0.5, 1, 2 and 5 barrels per day (bpd), 

we determined that VOC emissions at these condensate 

throughput rates would be approximately 3, 6, 12 and 30 

tpy, respectively. Similarly, we evaluated crude oil 

throughput rates of 1, 5, 20 and 50 bpd. Based on the Texas 

study, these crude oil throughput rates would result in VOC 

emissions of 0.3, 1.5, 5.8 and 14.6 tpy, respectively. We 

believe that it is important to control tanks with 

significant VOC emissions. Furthermore, we believe it would 
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be easier and less costly for owners and operators to 

determine applicability by using a throughput threshold 

instead of an emissions threshold. As a result of the above 

analyses, we believe that storage vessels with at least 1 

bpd of condensate or 20 bpd of crude oil should be 

controlled. These throughput rates are equivalent to VOC 

emissions of approximately 6 tpy. Based on an estimated 

annual cost of $18,900 for the control device, controlling 

storage vessels with these condensate or crude oil 

throughputs would result in a cost effectiveness of $3,150 

per ton of VOC reduced.

Based on our evaluation, we propose to determine that 

both a VRU and flare are BSER for reducing VOC emission 

from storage vessels with throughput of at least 1 barrel 

of condensate per day or 20 barrels of crude oil per day. 

We propose an NSPS of 95-percent reduction for these 

storage vessels to reflect the level of emission reduction 

achievable by VRU and flare control devices. 

For storage vessels below the throughput levels 

described above (“small throughput tanks”), for which we do 

not consider flares or VRU to be cost effective controls, 

we evaluated other measures to reduce VOC emissions. 

Standard practices for such tanks include requiring a cover 
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that is well designed, maintained in good condition and 

kept closed. Crude oil and condensate storage tanks in the 

oil and natural gas sector are designed to operate at or 

just slightly above or below atmospheric pressure. 

Accordingly, they are provided with vents to prevent tank 

destruction under rapid pressure increases due to flash 

emissions conditions. Studies by the Natural Gas STAR 

program and by others have shown that working losses (i.e., 

those emissions absent flash emission conditions) are very 

low, approaching zero. During times of flash emissions, 

tanks are designed such that the flash emissions are 

released through a vent on the fixed roof of the tank when 

pressure reaches just a few ounces to prevent pressure 

buildup and resulting tank damage. At those times, vapor 

readily escapes through the vent to protect the tank. Tests 

have shown that open hatches or leaking hatch gaskets have 

little effect on emissions from uncontrolled tanks due to 

the functioning roof vent. However, in the case of 

controlled tanks, the control requirements include 

provisions for maintaining integrity of the closed vent 

system that conveys emissions to the control device, 

including hatches and other tank openings. As a result, 

hatches are required to be kept closed and gaskets kept in 
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good repair to meet control requirements of controlled 

storage vessels. Because the measures we evaluated, 

including maintenance of hatch integrity, do not provide 

appreciable emission reductions for storage vessels with 

throughputs under 1 barrel of condensate per day and 21 

barrels of crude oil per day, we believe that the control 

options we evaluated do not reflect BSER for the small 

throughput tanks and we are not proposing standards for 

these tanks.

As discussed in section VII of this package, we are 

proposing to amend the NESHAP for oil and natural gas 

production facilities at 40 CFR part 63, subpart HH to 

require that all storage vessels at production facilities 

reduce HAP emissions by 95 percent. Because the controls 

used to achieve the 95-percent HAP reduction are the same 

as the proposed BSER for VOC reduction for storage vessels 

(i.e., VRU and flare), sources that are achieving the 95-

percent HAP reduction would also be meeting the proposed 

NSPS of 95-percent VOC reduction. In light of the above, 

and to avoid duplicate monitoring, recordkeeping and 

reporting, we propose that storage vessels subject to the 

requirements of subpart HH are exempt from the proposed 

NSPS for storage vessel in 40 CFR part 60, subpart OOOO.
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e. NSPS for VOC Equipment Leaks

Equipment leaks are fugitive emissions emanating from 

valves, pump seals, flanges, compressor seals, pressure 

relief valves, open-ended lines and other process and 

operation components. There are several potential reasons 

for equipment leak emissions. Components such as pumps, 

valves, pressure relief valves, flanges, agitators and 

compressors are potential sources that can leak due to seal 

failure. Other sources, such as open-ended lines and 

sampling connections may leak for reasons other than faulty 

seals. In addition, corrosion of welded connections, 

flanges, and valves may also be a cause of equipment leak 

emissions. Because of the large number of valves, pumps and 

other components within an oil and gas production, 

processing and transmission facility, equipment leak 

volatile emissions from these components can be 

significant. Natural gas processing plants, especially 

those using refrigerated absorption and transmission 

stations tend to have a large number of components. 

Equipment leaks from processing plants are addressed in our 

review of 40 CFR part 60, subpart KKK, which is discussed 

above in section VI.B.1. 
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In addition to gas processing plants, these types of 

equipment also exist at oil and gas production sites and 

gas transmission and storage facilities. While the number 

of components at individual transmission and storage 

facilities is relatively smaller than at processing plants, 

collectively, there are many components that can result in 

significant emissions. 

Therefore, we evaluated applying NSPS for equipment 

leaks to facilities in the production segment of the 

industry, which includes everything from the wellhead to 

the point that the gas enters the processing plant, 

transmission pipeline or distribution pipeline. Production 

facilities can vary significantly in the operations 

performed and the processes, all of which impact the number 

of components and potential emissions from leaking 

equipment and, thus, impact the annual costs related to 

implementing a LDAR program. We used data collected by the 

Gas Research Institute to develop model production 

facilities. Baseline emissions, along with emission 

reductions and costs of regulatory alternatives, were 

estimated using these model production facilities. We 

considered production facilities where separation, storage, 

compression and other processes occur. These facilities may 
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not have a wellhead on-site, but would be associated with a 

wellhead. We also evaluated gathering and boosting 

facilities, where gas and/or oil are collected from a 

number of wells, then processed and transported downstream 

to processing plants or transmission stations. We evaluated 

the impacts at these production facilities with varying 

number of operations and equipment. We also developed a 

model plant for the transmission and storage segment using 

data from the Gas Research Institute. Details of these

evaluations may be found in the TSD in the docket.

For an average production site at or associated with a 

wellhead, we estimated annual VOC emissions from equipment 

leaks of around 2.6 tpy. For an average gathering/boosting 

facility, we estimated the annual VOC emissions from 

equipment leaks to be around 9.8 tpy. The average 

transmission and storage facility emits 2.7 tpy of VOC. 

For facilities in each non-gas processing plant 

segment, we evaluated the same four options as we did for 

gas processing plants in section VI.B.1 above. These four 

options are as follows: (1) 40 CFR part 60, subpart VValevel LDAR (which is based on conducting Method 21 monthly, 

defining “leak” at 500 ppm threshold, and adding connectors 

to the VV list of components to be monitored); (2) monthly 
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optical gas imaging with annual Method 21 check (the 

alternative work practice for monitoring equipment for 

leaks at 40 CFR 60.18(g)); (3) monthly optical gas imaging 

alone; and (4) annual optical gas imaging alone. 

For option 1, we evaluated subpart VVa-LDAR as a 

whole. We also analyzed separately the individual types of 

components (valves, connectors, pressure relief devices and 

open-ended lines). Detailed discussions of these component 

by component analyses are included in the TSD in the 

docket. 

Based on our evaluation, subpart VVa-level LDAR 

(Option 1) results in more VOC reduction than the subpart 

VV-level LDAR currently required for gas processing plants, 

because more leaks are found based on the lower definition 

of “leak” under subpart VVa(10,000 ppm for subpart VV and 

500 ppm for subpart VVa). In addition, our evaluation 

shows that the cost per ton of VOC reduced for subpart VVa 

level controls is less than the cost per ton of VOC reduced 

for the less stringent subpart VV level of control. 

Although the cost of repairing more leaks is higher, the 

increased VOC control afforded by subpart VVa level 

controls more than offsets the increased costs. 
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For the subpart VVa level of control at the average 

production site associated with a wellhead, average 

facility-wide cost-effectiveness would be $16,084 per ton 

of VOC. Component-specific cost-effectiveness ranged from 

$15,063 per ton of VOC (for valves) to $211,992 per ton of 

VOC (for pressure relief devices), with connectors and 

open-ended lines being $74,283 and $180,537 per ton of VOC, 

respectively. We also looked at component costs for a 

modified subpart VVa level of control with less frequent 

monitoring for valves and connectors at production sites 

associated with a wellhead.

12 The cost-effectiveness for 

valves was calculated to be $17,828 per ton of VOC by 

reducing the monitoring frequency from monthly to annually. 

The cost-effectiveness for connectors was calculated to be 

$87,277 per ton of VOC by reducing the monitoring frequency 

from every 4 years to every 8 years after the initial 

compliance period. 

We performed a similar facility-wide and componentspecific analysis of option 1 LDAR for gathering and

boosting stations. For the subpart VVa level of control at 

the average gathering and boosting station, facility-wide 

cost-effectiveness was estimated to be $9,344 per ton of 

 
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VOC. Component-specific cost-effectiveness ranged from 

$6,079 per ton of VOC (for valves) to $77,310 per ton of 

VOC (for open-ended lines), with connectors and pressure 

relief devices being $23,603 and $72,523 per ton, 

respectively. For the modified subpart VVa level of 

control at gathering and boosting stations, costeffectiveness ranged from $5,221 per ton of VOC (for 

valves) to $77,310 per ton of VOC (for open-ended lines), 

with connectors and pressure relief devices being $27,274 

and $72,523 per ton, respectively. The modified subpart VVa 

level controls were more cost-effective than the subpart 

VVa level controls for valves, but not for connectors. 

This is due to the low cost of monitoring connectors and 

the low VOC emissions from leaking connectors. 

We also performed a similar analysis of option 1 

subpart VVa-level LDAR for gas transmission and storage 

facilities. For the subpart VVa level of control at the 

average transmission and storage facility, facility-wide 

cost-effectiveness was $20,215. Component-specific costeffectiveness ranged from $24,762 per ton of VOC (for openended lines) to $243,525 per ton of VOC (for pressure 

relief devices), with connectors and valves being $36,527 

and $43,111 per ton of VOC, respectively. For the modified 
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subpart VVa level of control at transmission and storage 

facilities, cost-effectiveness ranged from $24,762 per ton 

of VOC (for open-ended lines) to $243,525 per ton of VOC 

(for pressure relief devices), with connectors and valves 

being $42,140 and $40,593 per ton of VOC, respectively. 

Again, the modified subpart VVa level controls were more 

cost-effective for valves and less cost effective for 

connectors than the subpart VVa level controls. This is due 

to the low cost of monitoring connectors and the low VOC 

emissions from leaking connectors. 

For each of the non-gas processing segments, we also 

evaluated monthly optical gas imaging with annual Method 21 

check (Option 2). As discussed in secton VI.B.1, we had 

previously determined that the VOC reductions achieved 

under this option would be the same as for option 1 subpart 

VVa-level LDAR. In our evaluation of Option 2, we estimated 

that a single optical imaging instrument could be used for 

160 well sites and 13 gathering and boosting stations, 

which means that the cost of the purchase or rental of the 

camera would be spread across 173 facilities. 

For production sites, gathering and boosting stations, 

and transmission and storage facilities, we estimated that 

option 2 monthly optical gas imaging with annual Method 21 
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check would have cost-effectiveness of $16,123, $10,095, 

and $19,715 per ton of VOC, respectively.13

The annual costs for option 1 and option 2 leak 

detection and repair programs for production sites 

associated with a wellhead, gathering and boosting stations 

and transmission and storage facilities were higher than 

those estimated for natural gas processing plants because 

natural gas processing plant annual costs are based on the 

incremental cost of implementing subpart VVa-level 

standards, whereas the other facilities are not currently 

regulated under an LDAR program. The currently unregulated 

sites would be required to set up a new LDAR program; 

perform initial monitoring, tagging, logging and repairing 

of components; as well as planning and training personnel 

to implement the new LDAR program. 

In addition to options 1 and 2, we evaluated a third 

option that consisted of monthly optical gas imaging 

without an annual Method 21 check. Because we were unable 

to estimate the VOC emissions achieved by an optical 

imaging program alone, we were unable to estimate the costeffectiveness of this option. However, we estimated the 

 

13 Because optical gas imaging is used to view several pieces of 

equipment at a facility at once to survey for leaks, options 

involving imaging are not amenable to a component by component 

analysis.
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annual cost of the monthly optical gas imaging LDAR program 

at production sites, gathering and boosting stations, and 

transmission and storage facilities to be $37,049, $86,135, 

and $45,080, respectively, based on camera purchase, or 

$32,693, $81,780, and $40,629, respectively, based on 

camera rental. 

Finally, we evaluated a fourth option similar to the 

third option except that the optical gas imaging would be 

performed annually rather than monthly. For this option, we 

estimated the annual cost for production sites, gathering 

and boosting stations, and transmission and storage 

facilities to be $30,740, $64,416, and $24,031, 

respectively, based on camera purchase, or $26,341, 

$60,017, and $19,493, respectively, based on camera rental.

 We request comment on the applicability of a leak 

detection and repair program based solely on the use of 

optical imaging or other technologies. Of most use to us 

would be information on the effectiveness of advanced 

measurement technologies to detect and repair small leaks 

on the same order or smaller as specified in the VVa 

equipment leak requirements and the effects of increased 

frequency of and associated leak detection, recording, and 

repair practices.
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 Based on the evaluation described above, we believe 

that neither option 1 nor option 2 is cost effective for 

reducing fugitive VOC emissions from equipment leaks at 

sites, gathering and boosting stations, and transmission 

and storage facilities. For options 3 and 4, we were unable 

to estimate their cost effectiveness and, therefore, could 

not identify either of these two options as BSER for 

addressing equipment leak of VOC at production facilities 

associated with wellheads, at gathering and boosting 

stations or at gas transmission and storage facilities. We 

are, therefore, not proposing NSPS for addressing VOC 

emissions from equipment leaks at these facilities.

5. What are the SSM provisions?

The EPA is proposing standards in this rule that apply 

at all times, including during periods of startup or 

shutdown, and periods of malfunction. In proposing the 

standards in this rule, the EPA has taken into account 

startup and shutdown periods.

The General Provisions in 40 CFR part 60 require 

facilities to keep records of the occurrence and duration 

of any startup, shutdown or malfunction (40 CFR 60.7(b)) 

and either report to the EPA any period of excess emissions 

that occurs during periods of SSM (40 CFR 60.7(c)(2)) or 
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report that no excess emissions occurred (40 CFR 

60.7(c)(4)). Thus, any comments that contend that sources 

cannot meet the proposed standard during startup and 

shutdown periods should provide data and other specifics 

supporting their claim.

Periods of startup, normal operations and shutdown are 

all predictable and routine aspects of a source’s 

operations. However, by contrast, malfunction is defined as 

a “sudden, infrequent, and not reasonably preventable 

failure of air pollution control and monitoring equipment, 

process equipment or a process to operate in a normal or 

usual manner...” (40 CFR 60.2.) The EPA has determined that 

malfunctions should not be viewed as a distinct operating 

mode and, therefore, any emissions that occur at such times 

do not need to be factored into development of CAA section 

111 standards. Further, nothing in CAA section 111 or in 

case law requires that the EPA anticipate and account for 

the innumerable types of potential malfunction events in 

setting emission standards. See, Weyerhaeuser v Costle, 590 

F.2d 1011, 1058 (D.C. Cir. 1978) (“In the nature of things, 

no general limit, individual permit, or even any upset 

provision can anticipate all upset situations. After a 

certain point, the transgression of regulatory limits 
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caused by ‘uncontrollable acts of third parties,’ such as 

strikes, sabotage, operator intoxication or insanity, and a 

variety of other eventualities, must be a matter for the 

administrative exercise of case-by-case enforcement 

discretion, not for specification in advance by 

regulation.”), and, therefore, any emissions that occur at 

such times do not need to be factored into development of 

CAA section 111 standards.

Further, it is reasonable to interpret CAA section 111 

as not requiring the EPA to account for malfunctions in 

setting emissions standards. For example, we note that CAA 

section 111 provides that the EPA set standards of 

performance which reflect the degree of emission limitation 

achievable through “the application of the best system of 

emission reduction” that the EPA determines is adequately 

demonstrated. Applying the concept of “the application of 

the best system of emission reduction” to periods during 

which a source is malfunctioning presents difficulties. The 

“application of the best system of emission reduction” is 

more appropriately understood to include operating units in 

such a way as to avoid malfunctions.

Moreover, even if malfunctions were considered a 

distinct operating mode, we believe it would be 
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impracticable to take malfunctions into account in setting 

CAA section 111 standards for affected facilities under 40 

CFR part 60, subpart OOOO. As noted above, by definition, 

malfunctions are sudden and unexpected events and it would 

be difficult to set a standard that takes into account the 

myriad different types of malfunctions that can occur 

across all sources in the category. Moreover, malfunctions 

can vary in frequency, degree and duration, further 

complicating standard setting.

In the event that a source fails to comply with the 

applicable CAA section 111 standards as a result of a 

malfunction event, the EPA would determine an appropriate 

response based on, among other things, the good faith 

efforts of the source to minimize emissions during 

malfunction periods, including preventative and corrective 

actions, as well as root cause analyses to ascertain and 

rectify excess emissions. The EPA would also consider 

whether the source’s failure to comply with the CAA section 

111 standard was, in fact, “sudden, infrequent, not 

reasonably preventable” and was not instead “caused in part 

by poor maintenance or careless operation.” 40 CFR 60.2 

(definition of malfunction).

Finally, the EPA recognizes that even equipment that 
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is properly designed and maintained can sometimes fail. 

Such failure can sometimes cause an exceedance of the 

relevant emission standard (See, e.g., State Implementation 

Plans: Policy Regarding Excessive Emissions During 

Malfunctions, Startup, and Shutdown (September 20, 1999); 

Policy on Excess Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions (February 15, 1983)). The EPA 

is, therefore, proposing to add an affirmative defense to 

civil penalties for exceedances of emission limits that are 

caused by malfunctions. See 40 CFR 60.41Da (defining 

“affirmative defense” to mean, in the context of an 

enforcement proceeding, a response or defense put forward 

by a defendant, regarding which the defendant has the 

burden of proof and the merits of which are independently 

and objectively evaluated in a judicial or administrative 

proceeding). We also are proposing other regulatory 

provisions to specify the elements that are necessary to 

establish this affirmative defense; the source must prove 

by a preponderance of the evidence that it has met all of 

the elements set forth in 40 CFR 60.46Da. (See 40 CFR 

22.24). These criteria ensure that the affirmative defense 

is available only where the event that causes an exceedance 

of the emission limit meets the narrow definition of 
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malfunction in 40 CFR 60.2 (sudden, infrequent, not 

reasonably preventable and not caused by poor maintenance 

and or careless operation). For example, to successfully 

assert the affirmative defense, the source must prove by a 

preponderance of the evidence that excess emissions “[w]ere 

caused by a sudden, infrequent, and unavoidable failure of 

air pollution control and monitoring equipment, process 

equipment, or a process to operate in a normal or usual 

manner...” The criteria also are designed to ensure that 

steps are taken to correct the malfunction, to minimize 

emissions in accordance with 40 CFR 60.40Da and to prevent 

future malfunctions. For example, the source would have to 

prove by a preponderance of the evidence that “[r]epairs 

were made as expeditiously as possible when the applicable 

emission limitations were being exceeded...” and that 

“[a]ll possible steps were taken to minimize the impact of 

the excess emissions on ambient air quality, the 

environment and human health...” In any judicial or 

administrative proceeding, the Administrator may challenge 

the assertion of the affirmative defense and, if the 

respondent has not met the burden of proving all of the 

requirements in the affirmative defense, appropriate 

penalties may be assessed in accordance with CAA section 
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113 (see also 40 CFR part 22.77).

VII. Rationale for Proposed Action for NESHAP

A. What data were used for the NESHAP analyses?

To perform the technology review and residual risk

analysis for the two NESHAP, we created a comprehensive 

dataset (i.e., the MACT dataset). This dataset was based on 

the EPA’s 2005 National Emissions Inventory (NEI). The NEI 

database contains information about sources that emit 

criteria air pollutants and their precursors and HAP. The 

database includes estimates of annual air pollutant 

emissions from point, nonpoint and mobile sources in the 50 

states, the District of Columbia, Puerto Rico and the 

Virgin Islands. The EPA collects information about sources 

and releases an updated version of the NEI database every 3

years.

The NEI database is compiled from these primary 

sources: 

 Emissions inventories compiled by state and local 

environmental agencies 

 Databases related to the EPA's MACT programs 

 Toxics Release Inventory data 
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 For electric generating units, the EPA's Emission 

Tracking System/CEM data and United States Department 

of Energy (DOE) fuel use data 

 For onroad sources, the United States Federal Highway 

Administration’s estimate of vehicle miles traveled 

and emission factors from the EPA's MOBILE computer 

model 

 For nonroad sources, the EPA's NONROAD computer model 

 Emissions inventories from previous years, if states 

do not submit current data 

To concentrate on only records pertaining to the oil 

and natural gas industry sector, data were extracted using 

two criteria. First, we specified that all facilities 

containing codes identifying the Oil and Natural Gas 

Production and the Natural Gas Transmission and Storage 

MACT source categories (MACT codes 0501 and 0504, 

respectively). Second, we extracted facilities identified 

with the following NAICS codes: 211*** (Oil and Gas 

Extraction), 221210 (Natural Gas Distribution), 4861** 

(Pipeline Transportation of Crude Oil), and 4862**

(Pipeline Transportation of Natural Gas). Once the data 

were extracted, we reviewed the Source Classification Codes 

(SCC) to assess whether there were any records included in 
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the dataset that were clearly not a part of the oil and 

natural gas sector. Our review of the SCC also included 

assigning each SCC to an “Emission Process Group” that 

represents emission point types within the oil and natural 

gas sector.

Since these MACT standards only apply to major 

sources, only facilities designated as major sources in the 

NEI were extracted. In the NEI, sources are identified as 

major if the facility-wide emissions are greater than 10 

tpy for any single HAP or 25 tpy for any combination of 

HAP. We believe that this may overestimate the number of 

major sources in the oil and natural gas sector because it 

does not take into account the limitations set forth in the 

CAA regarding aggregation of emissions from wells and 

associated equipment in determining major source status.

The final dataset contained a total of 1,311 major 

sources in the oil and natural gas sector; 990 in Oil and 

Natural Gas Production, and 321 in Natural Gas Transmission 

and Storage. To assess how representative this number of 

facilities was, we obtained information on the number of 

subject facilities for both MACT standards from the 

Enforcement and Compliance History Online (ECHO) database. 

The ECHO database is a web-based tool (http://www.epa-
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echo.gov/echo/index.html) that provides public access to 

compliance and enforcement information for approximately 

800,000 EPA-regulated facilities. The ECHO database allows 

users to find permit, inspection, violation, enforcement 

action and penalty information covering the past 3 years. 

The site includes facilities regulated as CAA stationary 

sources, as well as Clean Water Act direct dischargers, and 

Resource Conservation and Recovery Act hazardous waste 

generators/handlers. The data in the ECHO database are 

updated monthly.

We performed a query on the ECHO database requesting 

records for major sources, with NAICS codes 211*, 221210, 

4861* and 4862*, with information for MACT. The ECHO 

database query identified records for a total of 555 

facilities, 269 in the Oil and Natural Gas Production 

source category (NAICS 211* and 221210) and 286 in the 

Natural Gas Transmission and Storage source category (NAICS 

4861* and 4862*). This comparison leads us to conclude 

that, for the Natural Gas Transmission and Storage segment, 

the NEI database is representative of the number of sources 

subject to the rule. For the Oil and Natural Gas Production 

source category, it confirms our assumption that the NEI 

dataset contains more facilities than are subject to the 
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rule. However, this provides a conservative overestimate of 

the number of sources, which we believe is appropriate for 

our risk analyses.

We are requesting that the public provide a detailed 

review of the information in this dataset and provide 

comments and updated information where appropriate. Section 

X of this preamble provides an explanation of how to 

provide updated information for these datasets.

B. What are the proposed decisions regarding certain 

unregulated emissions sources?

In addition to actions relative to the technology 

review and risk reviews discussed below, we are proposing,

pursuant to CAA sections 112(d)(2) and (3), MACT standards 

for glycol dehydrators and storage vessels for which 

standards were not previously developed. We are also 

proposing changes that affect the definition of “associated 

equipment” which could apply these MACT standards to 

previously unregulated sources.

1. Glycol Dehydrators

Once natural gas has been separated from any liquid 

materials or products (e.g., crude oil, condensate or 

produced water), residual entrained water is removed from 

the natural gas by dehydration. Dehydration is necessary 
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because water vapor may form hydrates, which are ice-like 

structures, and can cause corrosion in or plug equipment 

lines. The most widely used natural gas dehydration 

processes are glycol dehydration and solid desiccant 

dehydration. Solid desiccant dehydration, which is 

typically only used for lower throughputs, uses adsorption 

to remove water and is not a source of HAP emissions.

Glycol dehydration is an absorption process in which a 

liquid absorbent, glycol, directly contacts the natural gas 

stream and absorbs any entrained water vapor in a contact 

tower or absorption column. The majority of glycol 

dehydration units use triethylene glycol as the absorbent, 

but ethylene glycol and diethylene glycol are also used. 

The rich glycol, which has absorbed water vapor from the 

natural gas stream, leaves the bottom of the absorption 

column and is directed either to (1) a gas condensate 

glycol (GCG) separator (flash tank) and then a reboiler or 

(2) directly to a reboiler where the water is boiled off of 

the rich glycol. The regenerated glycol (lean glycol) is 

circulated, by pump, into the absorption tower. The vapor 

generated in the reboiler is directed to the reboiler vent. 

The reboiler vent is a source of HAP emissions. In the 

glycol contact tower, glycol not only absorbs water, but 
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also absorbs selected hydrocarbons, including BTEX and nhexane. The hydrocarbons are boiled off along with the 

water in the reboiler and vented to the atmosphere or to a 

control device. The most commonly used control device is a 

condenser. Condensers not only reduce emissions, but also 

recover condensable hydrocarbon vapors that can be 

recovered and sold. In addition, the dry non-condensable 

off-gas from the condenser may be used as fuel or recycled 

into the production process or directed to a flare, 

incinerator or other combustion device.

If present, the GCG separator (flash tank) is also a 

potential source of HAP emissions. Some glycol dehydration 

units use flash tanks prior to the reboiler to separate 

entrained gases, primarily methane and ethane from the 

glycol. The flash tank off-gases are typically recovered as 

fuel or recycled to the natural gas production header. 

However, the flash tank may also be vented directly to the 

atmosphere. Flash tanks typically enhance the reboiler 

condenser’s emission reduction efficiency by reducing the 

concentration of non-condensable gases present in the 

stream prior to being introduced into the condenser.

In the development of the MACT standards for the two 

oil and natural gas source categories, the EPA created two 
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subcategories of glycol dehydrators based on actual annual 

average natural gas flowrate and actual average benzene 

emissions. Under 40 CFR part 63, subpart HH, (the Oil and 

Natural Gas Production NESHAP), the EPA established MACT 

standards for glycol dehydration units with an actual 

annual average natural gas flowrate greater than or equal 

to 85,000 scmd and actual average benzene emissions greater 

than or equal to 0.90 Mg/yr (40 CFR 63.765(a)). The EPA did 

not establish standards for the other subcategory, which 

consists of glycol dehydration units that are below the 

flowrate and emission thresholds specified in subpart HH. 

Similarly, under 40 CFR part 63, subpart HHH (the Natural 

Gas Transmission and Storage NESHAP), the EPA established 

MACT standards for the subcategory of glycol dehydration 

units with an actual annual average natural gas flowrate 

greater than or equal to 283,000 scmd and actual average 

benzene emissions greater than or equal to 0.90 Mg/yr, but 

did not establish standards for the other subcategory, 

which consists of glycol dehydration units that are below 

the flowrate and emission thresholds specified in subpart 

HHH. As mentioned above, we refer to these unregulated 

dehydration units in both subparts HH and HHH as “small 

dehydrators” in this proposed rule.
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The EPA is proposing emission standards for these

subcategories of small dehydrators (i.e., those dehydrators 

with an actual annual average natural gas flowrate less 

than 85,000 scmd at production sites or 283,000 scmd at 

natural gas transmission and storage sites, or actual 

average benzene emissions less than 0.9 Mg/yr). Because we 

do not have any new emissions data concerning these 

emission points, we evaluated the dataset collected from 

industry during the development of the original MACT 

standards (legacy docket A-94-04, item II-B-01, disk 1 for 

oil and natural gas production facilities; and items IV-G24, 26, 27, 30 and 31 for natural gas transmission and 

storage facilities). We believe this dataset is 

representative of currently operating glycol dehydrators 

because it contains information for a varied group of 

sources (i.e., units owned by different companies, located 

in different states, representing a range of gas 

compositions and emission controls) and that the processes 

have not changed significantly since the data were 

collected. 

In the Oil and Natural Gas Production source category, 

there were 91 glycol dehydration units with throughput and 

emissions data identified that would be classified as small 
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glycol dehydration units. We evaluated the possibility of 

establishing a MACT floor as a Mg/yr limit. However, due to 

variability of gas throughput and inlet gas composition, we 

could not properly identify the best performing units by 

only considering emissions. To allow us to normalize the 

emissions for a more accurate determination of the best 

performing sources, we created an emission factor in terms 

of grams BTEX/scm-ppmv for each facility. The emission 

factor reflects the facility’s emission level, taking into 

consideration its natural gas throughput and inlet natural 

gas BTEX concentration. To determine the MACT floor for the 

existing dehydrators, we ranked each unit from lowest to 

highest, based on their emission factor, to determine the 

facilities in the top 12 percent of the dataset. The MACT 

floor was an emission factor of 1.10x10-4 grams BTEX/scmppmv. To meet this level of emissions, we anticipate that 

sources will use a variety of options, including, but not 

limited to, routing emissions to a condenser or to a 

combustion device. 

We also considered beyond-the-floor options for the 

existing sources, as required by section 112 (d)(2) of the 

CAA. To achieve further reductions beyond the MACT floor 

level of control, sources would have to install an 
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additional add-on control device, most likely a combustion 

device. Assuming the MACT floor control device is a 

combustion device, which generally achieves at least a 95-

percent HAP reduction, then less than 5 percent of the 

initial HAP emissions remain. Installing a second device 

would involve the same costs as the first control, but 

would only achieve 1/20 of the reduction (i.e., reducing 

the remaining 5 percent by another 95 percent represents a 

4.49-percent reduction of the initial, uncontrolled 

emissions, which is 1/20 of the 95-percent reduction 

achieved with the first control). Based on the $8,360/Mg 

cost effectiveness of the floor level of control, we 

estimate that the incremental cost effectiveness of the 

second control to be $167,200/Mg. We do not believe this 

cost to be reasonable given the level of emission 

reduction. We are, therefore, proposing an emission 

standard for existing small dehydrators that reflects the 

MACT floor.

For new small glycol dehydrators in the Oil and 

Natural Gas Production source category, based on our 

performance ranking, the best performing source has an 

emission factor of 4.66x10-6 grams BTEX/scm-ppmv. To meet 

this level of emissions, we anticipate that sources will 
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use a variety of options, including, but not limited to, 

routing emissions to a condenser or to a combustion device. 

The consideration of beyond-the-floor options for new small 

dehydrators would be the same as for existing small 

dehydrators, and, as stated above, we do not believe a cost

of $167,200/Mg to be reasonable given the level of emission 

reduction. We are, therefore, proposing a MACT standard for 

new small dehydrators that reflects the MACT floor level of 

control.

Under our proposal, a small dehydrator’s actual MACT 

emission limit would be determined by multiplying the MACT 

floor emission factor in g BTEX/scm-ppmv by its unitspecific incoming natural gas throughput and BTEX 

concentration for the dehydrator. A formula is provided in 

40 CFR 63.765(b)(1)(iii) to calculate the MACT limit as an 

annual value.

In the Natural Gas Transmission and Storage source 

category, there were 16 facilities for which throughput and 

emissions data were available that would be classified as 

small glycol dehydration units. Since the number of units 

was less than 30, the MACT floor for existing sources was 

based on the top five performing units. Using the same 

emission factor concept, we determined that the MACT floor 
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for existing sources is an emission factor equal to 6.42x10-

5 grams BTEX/scm-ppmv. To meet this level of emissions, we 

anticipate that sources will use a variety of options,

including, but not limited to, routing emissions to a 

condenser or to a combustion device. 

We also considered beyond-the-floor options for the 

existing small dehydrators as required by section 112 

(d)(2) of the CAA. To achieve further reductions beyond the 

MACT floor level of control, sources would have to install 

an additional add-on control device, most likely a 

combustion device. Assuming the MACT floor control device 

is a combustion device, which generally achieves at least a 

95-percent HAP reduction, then less than 5 percent of the 

initial HAP emissions remain. Installing a second device 

would involve the same costs as the first control device,

but would only achieve 1/20 of the reduction (i.e., 

reducing the remaining 5 percent by another 95 percent 

represents a 4.49-percent reduction of the initial, 

uncontrolled emissions, which is 1/20 of the 95-percent 

reduction achieved with the first control). Based on the 

$1,650/Mg cost effectiveness of the floor level of control, 

we estimate that the incremental cost effectiveness of the 

second control to be $33,000/Mg. We do not believe this 
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cost to be reasonable given the level of emission 

reduction. We are, therefore, proposing an emission 

standard for existing small dehydrators that reflects the 

MACT floor.

For new small glycol dehydrators, based on our 

performance ranking, the best performing source has an 

emission factor of 1.10x10-5 grams BTEX/scm-ppmv. To meet 

this level of emissions, we anticipate that sources will 

use a variety of options, including, but not limited to, 

routing emissions to a condenser or to a combustion device. 

The consideration of beyond-the-floor options for new small 

dehydrators would be the same as for existing small 

dehydrators, and, as stated above, we do not believe a cost

of $33,000/Mg to be reasonable given the level of emission 

reduction. We are, therefore, proposing an emission 

standard for new sources that reflects the MACT floor level 

of control.

Under our proposal, a source’s actual MACT emissions 

limit would be determined by multiplying this emission 

factor by their unit-specific incoming natural gas 

throughput and BTEX concentration for the dehydrator. A 

formula is provided in 40 CFR 63.1275(b)(1)(iii) to 

calculate the limit as an annual value. 
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As discussed below, we are proposing that, with the 

removal of the 1-ton alternative compliance option from the 

existing standards for glycol dehydrators, the MACT for 

these two source categories would provide an ample margin 

of safety to protect public health. We, therefore, maintain 

that, after the implementation of the small dehydrator 

standards discussed above, these MACT will continue to 

provide an ample margin of safety to protect public health. 

Consequently, we do not believe it will be necessary to 

conduct another residual risk review under CAA section 

112(f) for these two source categories 8 years following 

promulgation of the small dehydrator standards merely due 

to the addition of these new MACT requirements.

2. Storage Vessels

Crude oil, condensate and produced water are typically 

stored in fixed-roof storage vessels. Some vessels used for 

storing produced water may be open-top tanks. These 

vessels, which are operated at or near atmospheric pressure 

conditions, are typically located at tank batteries. A tank 

battery refers to the collection of process components used 

to separate, treat and store crude oil, condensate, natural 

gas and produced water. The extracted products from 

productions wells enter the tank battery through the 
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production header, which may collect product from many 

wells.

Emissions from storage vessels are a result of 

working, breathing and flash losses. Working losses occur 

due to the emptying and filling of storage tanks. Breathing 

losses are the release of gas associated with daily 

temperature fluctuations and other equilibrium effects. 

Flash losses occur when a liquid with entrained gases is 

transferred from a vessel with higher pressure to a vessel 

with lower pressure, thus, allowing entrained gases or a 

portion of the liquid to vaporize or flash. In the oil and 

natural gas production segment, flashing losses occur when 

live crude oils or condensates flow into a storage tank 

from a processing vessel operated at a higher pressure. 

Typically, the larger the pressure drop, the more flashing 

emission will occur in the storage stage. Temperature of 

the liquid may also influence the amount of flash 

emissions.

In the Oil and Natural Gas Production NESHAP (40 CFR 

part 63, subpart HH), the MACT standards for storage 

vessels apply only to those with the PFE. Storage vessels 

with the PFE are defined as storage vessels that contain 

hydrocarbon liquids that meet the following criteria:
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 A stock tank gas to oil ratio (GOR) greater than 

or equal to 0.31 cubic meters per liter 

(m3/liter); and 

 An American Petroleum Institute (API) gravity 

greater than or equal to 40 degrees; and 

 An actual annual average hydrocarbon liquid 

throughput greater than or equal to 79,500 liters 

per day (liter/day).

Accordingly, there is no emission limit in the 

existing MACT for storage vessels without the PFE. However, 

the MACT analysis performed at the time indicates that the 

MACT floor was based on all storage vessels, not just those 

vessels with flash emissions. See, Recommendation of MACT 

Floor Levels for HAP Emission Points at Major Sources in 

the Oil and Natural Gas Production Source Category,

(September 23, 1997, Docket A-94-04, Item II-A-07). We,

therefore, propose to apply the existing MACT for storage 

vessels with PFE to all storage vessels (i.e., storage 

vessels with the PFE, as well as those without the PFE).

3. Definition of Associated Equipment

CAA section 112(n)(4)(A) provides:

“Notwithstanding the provisions of subsection (a), 

emissions from any oil or gas exploration or 
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production well (with its associated equipment) and 

emission from any pipeline compressor or pump station 

shall not be aggregated with emissions from other 

similar units, whether or not such units are in 

contiguous area or under common control, to determine 

whether such units or stations are major sources.” 

As stated above, the CAA prevents aggregation of HAP 

emissions from wells and associated equipment in making 

major source determinations. In the absence of clear 

guidance in the statute on what constitutes “associated 

equipment,” the EPA sought to define “associated equipment” 

in a way that recognizes the need to implement relief for 

this industry as Congress intended and that also allow for 

the appropriate regulation of significant emission points. 

64 FR at 32619. Accordingly, in the existing Oil and 

Natural Gas Production NESHAP (1998 and 1999 NESHAP), the 

EPA defined “associated equipment” to exclude glycol 

dehydration units and storage vessels with PFE (thus 

allowing their emissions to be included in determining 

major source status) because EPA identified these sources 

as substantial contributors to HAP emissions. Id. EPA 

explained in that NESHAP that, because a single storage 

vessel with flash emissions may emit several Mg of HAP per 
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year and individual glycol dehydrators may emit above the 

major source level, storage vessels with PFE and glycol 

dehydrators are large individual sources of HAP, 63 FR

6288, 6301 (1998). The EPA therefore considered these 

emission sources substantial contributors to HAP emissions 

and excluded them from the definition of “associated 

equipment.” 64 FR at 32619. We have recently examined HAP 

emissions from storage vessels without flash emissions and 

found that these emissions are significant and comparable 

to those vessels with flash emissions. For example, one 

storage vessel with an API gravity of 30 degrees and a GOR 

of 2.09x10-

3 m3/liter with a throughput of 79,500 liter/day 

had HAP emissions of 9.91 Mg/yr, including 9.45 Mg/yr of nhexane. 

Because storage vessels without the PFE can have 

significant emissions at levels that are comparable to 

emissions from storage vessels with the PFE, there is no 

appreciable difference between storage vessels with the PFE 

and those without the PFE for purposes of defining 

“associated equipment.” We are, therefore, proposing to 

amend the associated equipment definition to exclude all 

storage vessels and not just storage vessels with the PFE.
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C. How did we perform the risk assessment and what are the 

results and proposed decisions?

1. How did we estimate risks posed by the source 

categories?

The EPA conducted risk assessments that provided 

estimates for each source in a category of the MIR posed by 

the HAP emissions, the HI for chronic exposures to HAP with 

the potential to cause noncancer health effects, and the 

hazard quotient (HQ) for acute exposures to HAP with the 

potential to cause noncancer health effects. The 

assessments also provided estimates of the distribution of 

cancer risks within the exposed populations, cancer 

incidence and an evaluation of the potential for adverse 

environmental effects for each source category. The risk 

assessments consisted of seven primary steps, as discussed 

below. The docket for this rulemaking contains the 

following document which provides more information on the 

risk assessment inputs and models: Draft Residual Risk 

Assessment for the Oil and Gas Production and Natural Gas 

Transmission and Storage Source Categories. The methods 

used to assess risks (as described in the seven primary 

steps below) are consistent with those peer-reviewed by a 

panel of the EPA’s Science Advisory Board (SAB) in 2009 and 
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described in their peer review report issued in 201014; they 

are also consistent with the key recommendations contained 

in that report.

a. Establishing the Nature and Magnitude of Actual 

Emissions and Identifying the Emissions Release 

Characteristics

As discussed in section VII.A of this preamble, we 

used a dataset based on the 2005 NEI as the basis for the 

risk assessment. In addition to the quality assurance (QA)

of the facilities contained in the dataset, we also checked 

the coordinates of every facility in the dataset through 

visual observations using tools such as GoogleEarth and 

ArcView. Where coordinates were found to be incorrect, we 

identified and corrected them to the extent possible. We 

also performed QA of the emissions data and release 

characteristics to ensure there were no outliers.

b. Establishing the Relationship Between Actual Emissions 

and MACT-Allowable Emissions Levels

The available emissions data in the MACT dataset 

represent the estimates of mass of emissions actually 

emitted during the specified annual time period. These 

 

14 U.S. EPA SAB. Risk and Technology Review (RTR) Risk Assessment 

Methodologies: For Review by the EPA’s Science Advisory Board 

with Case Studies – MACT I Petroleum Refining Sources and 

Portland Cement Manufacturing, May 2010.
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“actual” emission levels are often lower than the emission 

levels that a facility might be allowed to emit and still 

comply with the MACT standards. The emissions level allowed 

to be emitted by the MACT standards is referred to as the 

“MACT-allowable” emissions level. This represents the 

highest emissions level that could be emitted by the 

facility without violating the MACT standards. 

We discussed the use of both MACT-allowable and actual 

emissions in the final Coke Oven Batteries residual risk 

rule (70 FR 19998–19999, April 15, 2005) and in the 

proposed and final Hazardous Organic NESHAP residual risk 

rules (71 FR 34428, June 14, 2006, and 71 FR 76609, 

December 21, 2006, respectively). In those previous 

actions, we noted that assessing the risks at the MACTallowable level is inherently reasonable since these risks 

reflect the maximum level sources could emit and still 

comply with national emission standards. But we also 

explained that it is reasonable to consider actual 

emissions, where such data are available, in both steps of 

the risk analysis, in accordance with the Benzene NESHAP. 

(54 FR 38044, September 14, 1989.) 

To estimate emissions at the MACT-allowable level, we 

developed a ratio of MACT-allowable to actual emissions for 
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each emissions source type in each source category, based 

on the level of control required by the MACT standards 

compared to the level of reported actual emissions and 

available information on the level of control achieved by 

the emissions controls in use. 

c. Conducting Dispersion Modeling, Determining Inhalation 

Exposures and Estimating Individual and Population 

Inhalation Risks

Both long-term and short-term inhalation exposure 

concentrations and health risks from each source in the 

source categories addressed in this proposal were estimated 

using the Human Exposure Model (HEM) (Community and Sector 

HEM–3 version 1.1.0). The HEM–3 performs three primary risk 

assessment activities: (1) Conducting dispersion modeling 

to estimate the concentrations of HAP in ambient air, (2) 

estimating long-term and short-term inhalation exposures to 

individuals residing within 50 km of the modeled sources

and (3) estimating individual and population-level 

inhalation risks using the exposure estimates and 

quantitative dose-response information.

The dispersion model used by HEM–3 is AERMOD, which is 

one of the EPA’s preferred models for assessing pollutant 
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concentrations from industrial facilities.

15

To perform the 

dispersion modeling and to develop the preliminary risk 

estimates, HEM–3 draws on three data libraries. The first 

is a library of meteorological data, which is used for 

dispersion calculations. This library includes 1 year of 

hourly surface and upper air observations for more than 158 

meteorological stations, selected to provide coverage of 

the United States and Puerto Rico. A second library of 

United States Census Bureau census block

16

internal point 

locations and populations provides the basis of human 

exposure calculations (Census, 2000). In addition, for each 

census block, the census library includes the elevation and 

controlling hill height, which are also used in dispersion 

calculations. A third library of pollutant unit risk 

factors and other health benchmarks is used to estimate 

health risks. These risk factors and health benchmarks are 

the latest values recommended by the EPA for HAP and other 

toxic air pollutants. These values are available at 

http://www.epa.gov/ttn/atw/toxsource/summary.html and are 

discussed in more detail later in this section.

 

15

U.S. EPA. Revision to the Guideline on Air Quality Models: 

Adoption of a Preferred General Purpose (Flat and Complex 

Terrain) Dispersion Model and Other Revisions (70 FR 68218, 

November 9, 2005).

16

A census block is generally the smallest geographic area for 

which census statistics are tabulated. 
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In developing the risk assessment for chronic 

exposures, we used the estimated annual average ambient air 

concentration of each of the HAP emitted by each source for 

which we have emissions data in the source category. The 

air concentrations at each nearby census block centroid 

were used as a surrogate for the chronic inhalation 

exposure concentration for all the people who reside in 

that census block. We calculated the MIR for each facility 

as the cancer risk associated with a continuous lifetime 

(24 hours per day, 7 days per week, and 52 weeks per year 

for a 70-year period) exposure to the maximum concentration 

at the centroid of an inhabited census block. Individual 

cancer risks were calculated by multiplying the estimated 

lifetime exposure to the ambient concentration of each of 

the HAP (in micrograms per cubic meter) by its unit risk 

estimate (URE), which is an upper bound estimate of an 

individual’s probability of contracting cancer over a 

lifetime of exposure to a concentration of 1 microgram of 

the pollutant per cubic meter of air. For residual risk 

assessments, we generally use URE values from the EPA’s 

Integrated Risk Information System (IRIS). For carcinogenic 

pollutants without the EPA IRIS values, we look to other 

reputable sources of cancer dose-response values, often 
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using California EPA (CalEPA) URE values, where available. 

In cases where new, scientifically credible dose-response 

values have been developed in a manner consistent with the 

EPA guidelines and have undergone a peer review process 

similar to that used by the EPA, we may use such doseresponse values in place of or in addition to other values, 

if appropriate.

Formaldehyde is a unique case. In 2004, the EPA 

determined that the Chemical Industry Institute of 

Toxicology (CIIT) cancer dose-response value for 

formaldehyde (5.5 x 10-9 per μg/m3) was based on better 

science than the IRIS cancer dose-response value (1.3 x 10-

5 per μg/m3) and we switched from using the IRIS value to 

the CIIT value in risk assessments supporting regulatory 

actions. However, subsequent research published by the EPA 

suggests that the CIIT model was not appropriate and in 

2010 the EPA returned to using the 1991 IRIS value, which 

is more health protective.17 The EPA has been working on 

revising the formaldehyde IRIS assessment and the National 

Academy of Sciences (NAS) completed its review of the EPA’s 

draft in May of 2011. EPA is reviewing the public comments

 

17 For details on the justification for this decision, see the 

memorandum in the docket from Peter Preuss to Steve Page 

entitled, Recommendation for Formaldehyde Inhalation Cancer Risk 

Values, January 22, 2010.
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and the NAS independent scientific peer review, and the 

draft IRIS assessment will be revised and the final 

assessment will be posted on the IRIS database. In the 

interim, we will present findings using the 1991 IRIS value 

as a primary estimate, and may also consider other 

information as the science evolves.

In the case of benzene, the high end of the reported 

cancer URE range was used in our assessments to provide a 

conservative estimate of potential cancer risks. Use of the 

high end of the range provides risk estimates that are 

approximately 3.5 times higher than use of the equallyplausible low end value. We also evaluated the impact of 

using the low end of the URE range on our risk results.

We also note that polycyclic organic matter (POM), a 

carcinogenic HAP with a mutagenic mode of action, is 

emitted by some of the facilities in these two categories.

18

For this compound group,

19

the age-dependent adjustment 

factors (ADAF) described in the EPA’s Supplemental Guidance 

for Assessing Susceptibility from Early-Life Exposure to 

 

18

U.S. EPA. Performing risk assessments that include carcinogens 

described in the Supplemental Guidance as having a mutagenic mode 

of action. Science Policy Council Cancer Guidelines 

Implementation Work Group Communication II: Memo from W.H. 

Farland, dated October 4, 2005.

19

See the Risk Assessment for Source Categories document 

available in the docket for a list of HAP with a mutagenic mode 

of action.
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Carcinogens

20

were applied. This adjustment has the effect 

of increasing the estimated lifetime risks for POM by a 

factor of 1.6. In addition, although only a small fraction 

of the total POM emissions were not reported as individual 

compounds, the EPA expresses carcinogenic potency for 

compounds in this group in terms of benzo[a]pyrene 

equivalence, based on evidence that carcinogenic POM has 

the same mutagenic mechanism of action as benzo[a]pyrene. 

For this reason, the EPA’s Science 

Policy Council

21

recommends applying the Supplemental 

Guidance to all carcinogenic polycyclic aromatic 

hydrocarbons for which risk estimates are based on relative 

potency. Accordingly, we have applied the ADAF to the 

benzo[a]pyrene equivalent portion of all POM mixtures.

Incremental individual lifetime cancer risks 

associated with emissions from the source category were 

estimated as the sum of the risks for each of the 

carcinogenic HAP (including those classified as 

carcinogenic to humans, likely to be carcinogenic to humans 

 

20

U.S. EPA. Supplemental Guidance for Assessing Early-Life 

Exposure to Carcinogens. EPA/630/R-03/003F, 2005. 

http://www.epa.gov/ttn/atw/childrens_supplement_final.pdf.

21

U.S. EPA. Science Policy Council Cancer Guidelines 

Implementation Workgroup Communication II: Memo from W.H. 

Farland, dated June 14, 2006.
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and suggestive evidence of carcinogenic potential

22

) emitted 

by the modeled source. Cancer incidence and the 

distribution of individual cancer risks for the population 

within 50 km of any source were also estimated for the 

source category as part of these assessments by summing 

individual risks. A distance of 50 km is consistent with 

both the analysis supporting the 1989 Benzene NESHAP (54 FR 

38044) and the limitations of Gaussian dispersion models, 

including AERMOD. 

To assess risk of noncancer health effects from 

chronic exposures, we summed the HQ for each of the HAP 

that affects a common target organ system to obtain the HI 

for that target organ system (or target organ-specific HI, 

TOSHI). The HQ for chronic exposures is the estimated 

chronic exposure divided by the chronic reference level, 

which is either the EPA reference concentration (RfC), 

defined as “an estimate (with uncertainty spanning perhaps 

 

22

These classifications also coincide with the terms "known 

carcinogen, probable carcinogen and possible carcinogen," 

respectively, which are the terms advocated in the EPA's previous 

Guidelines for Carcinogen Risk Assessment, published in 1986 (51 

FR 33992, September 24, 1986). Summing the risks of these 

individual compounds to obtain the cumulative cancer risks is an 

approach that was recommended by the EPA's SAB in their 2002 peer 

review of EPA's NATA entitled, NATA - Evaluating the Nationalscale Air Toxics Assessment 1996 Data -- an SAB Advisory, 

available at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/214C6E915BB04E14852570

CA007A682C/$File/ecadv02001.pdf.
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an order of magnitude) of a continuous inhalation exposure 

to the human population (including sensitive subgroups) 

that is likely to be without an appreciable risk of 

deleterious effects during a lifetime,” or, in cases where 

an RfC from the EPA’s IRIS database is not available, the 

EPA will utilize the following prioritized sources for our 

chronic dose-response values: (1) The Agency for Toxic 

Substances and Disease Registry Minimum Risk Level, which 

is defined as “an estimate of daily human exposure to a 

substance that is likely to be without an appreciable risk 

of adverse effects (other than cancer) over a specified 

duration of exposure”; (2) the CalEPA Chronic Reference 

Exposure Level (REL), which is defined as “the 

concentration level at or below which no adverse health 

effects are anticipated for a specified exposure duration”; 

and (3), as noted above, in cases where scientifically 

credible dose-response values have been developed in a 

manner consistent with the EPA guidelines and have 

undergone a peer review process similar to that used by the 

EPA, we may use those dose-response values in place of or 

in concert with other values.

Screening estimates of acute exposures and risks were 

also evaluated for each of the HAP at the point of highest 
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off-site exposure for each facility (i.e., not just the 

census block centroids), assuming that a person is located 

at this spot at a time when both the peak (hourly) emission 

rate and worst-case dispersion conditions (1991 calendar 

year data) occur. The acute HQ is the estimated acute 

exposure divided by the acute dose-response value. In each 

case, acute HQ values were calculated using best available, 

short-term dose-response values. These acute dose-response 

values, which are described below, include the acute REL, 

acute exposure guideline levels (AEGL) and emergency 

response planning guidelines (ERPG) for 1-hour exposure 

durations. As discussed below, we used conservative 

assumptions for emission rates, meteorology and exposure 

location for our acute analysis. 

As described in the CalEPA’s Air Toxics Hot Spots 

Program Risk Assessment Guidelines, Part I, The 

Determination of Acute Reference Exposure Levels for 

Airborne Toxicants, an acute REL value 

(http://www.oehha.ca.gov/air/pdf/acuterel.pdf) is defined 

as “the concentration level at or below which no adverse 

health effects are anticipated for a specified exposure 

duration.” Acute REL values are based on the most 

sensitive, relevant, adverse health effect reported in the 
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medical and toxicological literature. Acute REL values are 

designed to protect the most sensitive individuals in the 

population by the inclusion of margins of safety. Since 

margins of safety are incorporated to address data gaps and 

uncertainties, exceeding the acute REL does not 

automatically indicate an adverse health impact.

AEGL values were derived in response to 

recommendations from the National Research Council (NRC). 

As described in Standing Operating Procedures (SOP) of the 

National Advisory Committee on Acute Exposure Guideline 

Levels for Hazardous Substances

(http://www.epa.gov/opptintr/aegl/pubs/sop.pdf),

23

“the 

NRC’s previous name for acute exposure levels—community 

emergency exposure levels—was replaced by the term AEGL to 

reflect the broad application of these values to planning, 

response, and prevention in the community, the workplace, 

transportation, the military, and the remediation of 

Superfund sites.” This document also states that AEGL 

values “represent threshold exposure limits for the general 

public and are applicable to emergency exposures ranging 

from 10 minutes to eight hours.” The document lays out the 

purpose and objectives of AEGL by stating (page 21) that 

 

23

NAS, 2001. Standing Operating Procedures for Developing Acute 

Exposure Levels for Hazardous Chemicals, page 2.
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“the primary purpose of the AEGL program and the National 

Advisory Committee for Acute Exposure Guideline Levels for 

Hazardous Substances is to develop guideline levels for 

once-in-a-lifetime, short-term exposures to airborne 

concentrations of acutely toxic, high-priority chemicals.” 

In detailing the intended application of AEGL values, the 

document states (page 31) that “[i]t is anticipated that 

the AEGL values will be used for regulatory and 

nonregulatory purposes by U.S. Federal and state agencies

and possibly the international community in conjunction 

with chemical emergency response, planning, and prevention 

programs. More specifically, the AEGL values will be used 

for conducting various risk assessments to aid in the 

development of emergency preparedness and prevention plans, 

as well as real-time emergency response actions, for 

accidental chemical releases at fixed facilities and from 

transport carriers.”

The AEGL–1 value is then specifically defined as “the 

airborne concentration of a substance above which it is 

predicted that the general population, including 

susceptible individuals, could experience notable 

discomfort, irritation, or certain asymptomatic nonsensory 

effects. However, the effects are not disabling and are 
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transient and reversible upon cessation of exposure.” The 

document also notes (page 3) that, “Airborne concentrations 

below AEGL–1 represent exposure levels that can produce 

mild and progressively increasing but transient and 

nondisabling odor, taste, and sensory irritation or certain 

asymptomatic, nonsensory effects.” Similarly, the document 

defines AEGL–2 values as “the airborne concentration 

(expressed as ppm or mg/m3) of a substance above which it 

is predicted that the general population, including 

susceptible individuals, could experience irreversible or 

other serious, long-lasting adverse health effects or an 

impaired ability to escape.”

ERPG values are derived for use in emergency response, 

as described in the American Industrial Hygiene 

Association’s document entitled, Emergency Response 

Planning Guidelines (ERPG) Procedures and Responsibilities

(http://www.aiha.org/1documents/committees/ERPSOPs2006.pdf) 

which states that, “Emergency Response Planning Guidelines 

were developed for emergency planning and are intended as 

health based guideline concentrations for single exposures 

to chemicals.”

24

The ERPG–1 value is defined as “the maximum 

airborne concentration below which it is believed that 

 

24

ERP Committee Procedures and Responsibilities. November 1, 

2006. American Industrial Hygiene Association.
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nearly all individuals could be exposed for up to 1 hour 

without experiencing other than mild transient adverse 

health effects or without perceiving a clearly defined, 

objectionable odor.” Similarly, the ERPG–2 value is defined 

as “the maximum airborne concentration below which it is 

believed that nearly all individuals could be exposed for 

up to 1 hour without experiencing or developing 

irreversible or other serious health effects or symptoms 

which could impair an individual’s ability to take 

protective action.”

As can be seen from the definitions above, the AEGL 

and ERPG values include the similarly-defined severity 

levels 1 and 2. For many chemicals, a severity level 1 

value AEGL or ERPG has not been developed; in these 

instances, higher severity level AEGL–2 or ERPG–2 values 

are compared to our modeled exposure levels to screen for 

potential acute concerns.

Acute REL values for 1-hour exposure durations are 

typically lower than their corresponding AEGL–1 and ERPG–1 

values. Even though their definitions are slightly 

different, AEGL–1 values are often the same as the 

corresponding ERPG–1 values, and AEGL–2 values are often 

equal to ERPG–2 values. Maximum HQ values from our acute 
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screening risk assessments typically result when basing 

them on the acute REL value for a particular pollutant. In 

cases where our maximum acute HQ value exceeds 1, we also 

report the HQ value based on the next highest acute doseresponse value (usually the AEGL–1 and/or the ERPG–1 

value). 

To develop screening estimates of acute exposures, we 

developed estimates of maximum hourly emission rates by 

multiplying the average actual annual hourly emission rates 

by a factor to cover routinely variable emissions. We chose 

the factor based on process knowledge and engineering 

judgment and with awareness of a Texas study of short-term 

emissions variability, which showed that most peak emission 

events, in a heavily-industrialized 4-county area (Harris, 

Galveston, Chambers and Brazoria Counties, Texas) were less 

than twice the annual average hourly emission rate. The 

highest peak emission event was 74 times the annual average 

hourly emission rate, and the 99th percentile ratio of peak 

hourly emission rate to the annual average hourly emission 

rate was 9.

25

This analysis is provided in Appendix 4 of the 

Draft Residual Risk Assessment for the Oil and Gas 

 

25

See 

http://www.tceq.state.tx.us/compliance/field_ops/eer/index.html 

or docket to access the source of these data.
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Production and Natural Gas Transmission and Storage Source 

Categories, which is available in the docket for this 

action. Considering this analysis, unless specific process 

knowledge or data are available to provide an alternate 

value, to account for more than 99 percent of the peak 

hourly emissions, we apply a conservative screening 

multiplication factor of 10 to the average annual hourly 

emission rate in these acute exposure screening 

assessments. The factor of 10 was used for both the Oil and 

Natural Gas Production and the Natural Gas Transmission and 

Storage source categories. 

In cases where acute HQ values from the screening step 

were less than or equal to 1, acute impacts were deemed 

negligible and no further analysis was performed. In cases 

where an acute HQ from the screening step was greater than 

1, additional site-specific data were considered to develop 

a more refined estimate of the potential for acute impacts 

of concern. The data refinements employed for these source 

categories consisted of using the site-specific facility 

layout to distinguish facility property from an area where 

the public could be exposed. These refinements are 

discussed in the draft risk assessment document, which is

available in the docket for each of these source 
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categories. Ideally, we would prefer to have continuous 

measurements over time to see how the emissions vary by 

each hour over an entire year. Having a frequency 

distribution of hourly emission rates over a year would 

allow us to perform a probabilistic analysis to estimate 

potential threshold exceedances and their frequency of 

occurrence. Such an evaluation could include a more 

complete statistical treatment of the key parameters and 

elements adopted in this screening analysis. However, we 

recognize that having this level of data is rare, hence our 

use of the multiplier approach.

To better characterize the potential health risks 

associated with estimated acute exposures to HAP, and in 

response to a key recommendation from the SAB’s peer review 

of the EPA’s RTR risk assessment methodologies,

26 we 

generally examine a wider range of available acute health 

metrics than we do for our chronic risk assessments. This 

is in response to the SAB’s acknowledgement that there are 

generally more data gaps and inconsistencies in acute 

reference values than there are in chronic reference 

values. Comparisons of the estimated maximum off-site 1-

 

26 The SAB peer review of RTR Risk Assessment Methodologies is 

available at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/4AB3966E263D943A852577

1F00668381/$File/EPA-SAB-10-007-unsigned.pdf.
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hour exposure levels are not typically made to occupational 

levels for the purpose of characterizing public health 

risks in RTR assessments. This is because they are 

developed for working age adults and are not generally 

considered protective for the general public. We note that 

occupational ceiling values are, for most chemicals, set at 

levels higher than a 1-hour AEGL-1.

As discussed in section VII.C.2 of this preamble, the 

maximum estimated worst-case 1-hour exposure to benzene 

outside the facility fence line for a facility in either 

source category is 12 mg/m3. This estimated exposure exceeds 

the 6-hour REL by a factor of 9 (HQREL = 9), but is 

significantly below the 1-hour AEGL-1 (HQAEGL-1 = 0.07). 

Although this worst-case exposure estimate does not exceed 

the AEGL-1, we note here that it slightly exceeds workplace 

ceiling level guidelines designed to protect the worker 

population for short duration (<15 minute) increases in 

exposure to benzene, as discussed below. The occupational 

short-term exposure limit (STEL) standard for benzene 

developed by the Occupational Safety and Health 

Administration is 16 mg/m3, “as averaged over any 15-minute 
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period.”27 Occupational guideline STEL for exposures to 

benzene have also been developed by the American Conference 

of Governmental Industrial Hygienists (ACGIH)

28 for less 

than 15 minutes29 (ACGIH threshold limit value (TLV)-STEL 

value of 8.0 mg/m3), and by the National Institute for 

Occupational Safety and Health (NIOSH)

30 “for any 15 minute 

period in a work day” (NIOSH REL-STEL of 3.2 mg/m3). These 

shorter duration occupational values indicate potential 

concerns regarding health effects at exposure levels below 

the 1-hour AEGL-1 value. We solicit comment on the use of 

the occupational values described above in the 

interpretation of these worst-case acute screening exposure 

estimates.

d. Conducting Multi-Pathway Exposure and Risk Modeling

The potential for significant human health risks due 

to exposures via routes other than inhalation (i.e., multi-

 

27 29 CFR 1910.1028, Benzene. Available online at 

http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=STA

NDARDS&p_id=10042.

28 ACGIH (2001) Benzene. In Documentation of the TLVs® and BEIs® 

with Other Worldwide Occupational Exposure Values. ACGIH, 1300 

Kemper Meadow Drive, Cincinnati, OH 45240 (ISBN: 978-1-882417-74-

2) and available online at http://www.acgih.org. 

29 The ACGIH definition of a TLV-STEL states that “Exposures above 

the TLV-TWA up to the TLV-STEL should be less than 15 minutes, 

should occur no more than four times per day, and there should be 

at least 60 minutes between successive exposures in this range.”

30 NIOSH. Occupational Safety and Health Guideline for Benzene; 

http://www.cdc.gov/niosh/74-137.html.
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pathway exposures) and the potential for adverse 

environmental impacts were evaluated in a three-step 

process. In the first step, we determined whether any 

facilities emitted any HAP known to be PB-HAP (HAP known to 

be persistent and bio-accumulative) in the environment. 

There are 14 PB-HAP compounds or compound classes 

identified for this screening in the EPA’s Air Toxics Risk 

Assessment Library (available at 

http://www.epa.gov/ttn/fera/risk_atra_vol1.html). They are 

cadmium compounds, chlordane, chlorinated dibenzodioxins 

and furans, dichlorodiphenyldichloroethylene, heptachlor, 

hexachlorobenzene, hexachlorocyclohexane, lead compounds, 

mercury compounds, methoxychlor, polychlorinated biphenyls, 

POM, toxaphene and trifluralin. 

Since one or more of these PB-HAP are emitted by at 

least one facility in both source categories, we proceeded 

to the second step of the evaluation. In this step, we 

determined whether the facility-specific emission rates of 

each of the emitted PB–HAP were large enough to create the 

potential for significant non-inhalation human or 

environmental risks under reasonable worst-case conditions. 

To facilitate this step, we have developed emission rate 

thresholds for each PB–HAP using a hypothetical worst-case 
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screening exposure scenario developed for use in 

conjunction with the EPA’s TRIM.FaTE model. The 

hypothetical screening scenario was subjected to a 

sensitivity analysis to ensure that its key design 

parameters were established such that environmental media 

concentrations were not underestimated (i.e., to minimize 

the occurrence of false negatives or results that suggest 

that risks might be acceptable when, in fact, actual risks 

are high) and to also minimize the occurrence of false 

positives for human health endpoints. We call this 

application of the TRIM.FaTE model TRIM-Screen. The 

facility-specific emission rates of each of the PB–HAP in 

each source category were compared to the TRIM-Screen 

emission threshold values for each of the PB–HAP identified 

in the source category datasets to assess the potential for 

significant human health risks or environmental risks via 

non-inhalation pathways. 

There was only one facility in the Natural Gas 

Transmission and Storage source category with reported 

emissions of PB-HAP, and the emission rates were less than 

the emission threshold values. There were 29 facilities in 

the Oil and Natural Gas Production source category with 

reported emissions of PB-HAP, and one of these had emission 
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rates greater than the emission threshold values. In this 

case, the emission threshold value for POM was exceeded by 

a factor of 6. For POM, dairy, vegetables and fruits were 

the three most dominant exposure pathways driving human 

exposures in the hypothetical screening exposure scenario. 

The single facility with emissions exceeding the emission 

threshold value for POM is located in a highly 

industrialized area. Therefore, since the exposure pathways 

which would drive high human exposure are not locally 

available, multi-pathway exposures and environmental risks 

were deemed negligible, and no further analysis was 

performed. For further information on the multi-pathway 

analysis approach, see the residual risk documentation.

e. Assessing Risks Considering Emissions Control Options

In addition to assessing baseline inhalation risks and 

screening for potential multi-pathway risks, where 

appropriate, we also estimated risks considering the 

potential emission reductions that would be achieved by the 

particular control options under consideration. In these 

cases, the expected emissions reductions were applied to 

the specific HAP and emissions sources in the source 

category dataset to develop corresponding estimates of risk 

reductions.
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f. Conducting Other Risk-Related Analyses: Facility-Wide 

Assessments

To put the source category risks in context, we also 

examined the risks from the entire “facility,” where the 

facility includes all HAP-emitting operations within a 

contiguous area and under common control. In other words, 

for each facility that includes one or more sources from 

one of the source categories under review, we examined the 

HAP emissions not only from the source category of 

interest, but also from all other emission sources at the 

facility. The emissions data for generating these 

“facility-wide” risks were also obtained from the 2005 NEI. 

For every facility included in the MACT database, we also 

retrieved emissions data and release characteristics for 

all other emission sources at the same facility. We 

estimated the risks due to the inhalation of HAP that are 

emitted “facility-wide” for the populations residing within 

50 km of each facility, consistent with the methods used 

for the source category analysis described above. For these 

facility-wide risk analyses, the modeled source category 

risks were compared to the facility-wide risks to determine 

the portion of facility-wide risks that could be attributed 

to the source categories addressed in this proposal. We 
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specifically examined the facilities associated with the 

highest estimates of risk and determined the percentage of 

that risk attributable to the source category of interest. 

The risk documentation available through the docket for 

this action provides the methodology and the results of the 

facility-wide analyses for each source category. 

g. Conducting Other Analyses: Demographic Analysis

To examine the potential for any environmental justice 

(EJ) issues that might be associated with each source 

category, we performed a demographic analysis of population 

risk. In this analysis, we evaluated the distributions of 

HAP-related cancer and noncancer risks across different 

social, demographic and economic groups within the 

populations living near the facilities where these source 

categories are located. The development of demographic 

analyses to inform the consideration of EJ issues in the 

EPA rulemakings is an evolving science. The EPA offers the 

demographic analyses in this rulemaking to inform the 

consideration of potential EJ issues and invites public 

comment on the approaches used and the interpretations made 

from the results, with the hope that this will support the 

refinement and improve the utility of such analyses for 

future rulemakings.
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For the demographic analyses, we focus on the 

populations within 50 km of any facility estimated to have 

exposures to HAP which result in cancer risks of 1-in-1 

million or greater, or noncancer HI of 1 or greater (based 

on the emissions of the source category or the facility, 

respectively). We examine the distributions of those risks 

across various demographic groups, comparing the 

percentages of particular demographic groups to the total 

number of people in those demographic groups nationwide. 

The results, including other risk metrics, such as average 

risks for the exposed populations, are documented in 

source-category-specific technical reports in the docket 

for both source categories covered in this proposal.

The basis for the risk values used in these analyses 

were the modeling results based on actual emissions levels 

obtained from the HEM-3 model described above. The risk 

values for each census block were linked to a database of 

information from the 2000 Decennial census that includes 

data on race and ethnicity, age distributions, poverty 

status, household incomes and education level. The Census 

Department Landview® database was the source of the data on 

race and ethnicity and the data on age distributions, 

poverty status, household incomes and education level were 
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obtained from the 2000 Census of Population and Housing 

Summary File 3 Long Form. While race and ethnicity census 

data are available at the census block level, the age and 

income census data are only available at the census block 

group level (which includes an average of 26 blocks or an 

average of 1,350 people). Where census data are available 

at the block group level, but not the block level, we 

assumed that all census blocks within the block group have 

the same distribution of ages and incomes as the block 

group. 

For each source category, we focused on those census 

blocks where source category risk results show estimated 

lifetime inhalation cancer risks above 1-in-1 million or 

chronic noncancer indices above 1 and determined the 

relative percentage of different racial and ethnic groups, 

different age groups, adults with and without a high school 

diploma, people living in households below the national 

median income and for people living below the poverty line 

within those census blocks. The specific census population 

categories studied include: 

• Total population

• White

• African American (or Black)
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• Native Americans

• Other races and multiracial

• Hispanic or Latino 

• Children 18 years of age and under

• Adults 19 to 64 years of age

• Adults 65 years of age and over 

• Adults without a high school diploma

• Households earning under the national median income

• People living below the poverty line

It should be noted that these categories overlap in 

some instances, resulting in some populations being counted 

in more than one category (e.g., other races and 

multiracial and Hispanic). In addition, while not a 

specific census population category, we also examined risks 

to “Minorities,” a classification which is defined for 

these purposes as all race population categories except 

white. 

For further information about risks to the populations 

located near the facilities in these source categories, we 

also evaluated the estimated distribution of inhalation 

cancer and chronic noncancer risks associated with the HAP 

emissions from all the emissions sources at the facility 

(i.e., facility-wide). This analysis used the facility-wide 
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RTR modeling results and the census data described above. 

The methodology and the results of the demographic 

analyses for each source category are included in a sourcecategory-specific technical report for each of the 

categories, which are available in the docket for this 

action.

h. Considering Uncertainties in Risk Assessment

Uncertainty and the potential for bias are inherent in 

all risk assessments, including those performed for the 

source categories addressed in this proposal. Although 

uncertainty exists, we believe that our approach, which 

used conservative tools and assumptions, ensures that our 

decisions are health-protective. A brief discussion of the 

uncertainties in the emissions datasets, dispersion 

modeling, inhalation exposure estimates and dose-response 

relationships follows below. A more thorough discussion of 

these uncertainties is included in the risk assessment 

documentation (referenced earlier) available in the docket 

for this action.

i. Uncertainties in the Emissions Datasets

Although the development of the MACT dataset involved 

QA/quality control processes, the accuracy of emissions 

values will vary depending on the source of the data, the 
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degree to which data are incomplete or missing, the degree 

to which assumptions made to complete the datasets are 

inaccurate, errors in estimating emissions values and other 

factors. The emission estimates considered in this analysis 

generally are annual totals for certain years that do not 

reflect short-term fluctuations during the course of a year 

or variations from year to year. 

The estimates of peak hourly emission rates for the 

acute effects screening assessment were based on a 

multiplication factor of 10 applied to the average annual 

hourly emission rate, which is intended to account for 

emission fluctuations due to normal facility operations. 

Additionally, although we believe that we have data for 

most facilities in these two source categories in our RTR 

dataset, our dataset may not include data for all existing 

facilities. Moreover, there are uncertainties with regard 

to the identification of sources as major or area in the 

NEI for these source categories. 

ii. Uncertainties in Dispersion Modeling

While the analysis employed the EPA’s recommended 

regulatory dispersion model, AERMOD, we recognize that 

there is uncertainty in ambient concentration estimates 

associated with any model, including AERMOD. In 
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circumstances where we had to choose between various model 

options, where possible, model options (e.g., rural/urban, 

plume depletion, chemistry) were selected to provide an 

overestimate of ambient air concentrations of the HAP 

rather than underestimates. However, because of 

practicality and data limitation reasons, some factors 

(e.g., meteorology, building downwash) have the potential 

in some situations to overestimate or underestimate ambient 

impacts. For example, meteorological data were taken from a 

single year (1991) and facility locations can be a 

significant distance from the site where these data were 

taken. Despite these uncertainties, we believe that at offsite locations and census block centroids, the approach 

considered in the dispersion modeling analysis should 

generally yield overestimates of ambient HAP 

concentrations.

iii. Uncertainties in inhalation exposure

The effects of human mobility on exposures were not 

included in the assessment. Specifically, short-term 

mobility and long-term mobility between census blocks in 

the modeling domain were not considered.

31

The assumption of 

 

31

Short-term mobility is movement from one micro-environment to 

another over the course of hours or days. Long-term mobility is 
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not considering short or long-term population mobility does 

not bias the estimate of the theoretical MIR, nor does it 

affect the estimate of cancer incidence since the total 

population number remains the same. It does, however, 

affect the shape of the distribution of individual risks 

across the affected population, shifting it toward higher 

estimated individual risks at the upper end and reducing 

the number of people estimated to be at lower risks, 

thereby increasing the estimated number of people at 

specific risk levels.

In addition, the assessment predicted the chronic 

exposures at the centroid of each populated census block as 

surrogates for the exposure concentrations for all people 

living in that block. Using the census block centroid to 

predict chronic exposures tends to over-predict exposures 

for people in the census block who live further from the 

facility, and under-predict exposures for people in the 

census block who live closer to the facility. Thus, using 

the census block centroid to predict chronic exposures may 

lead to a potential understatement or overstatement of the 

true maximum impact, but is an unbiased estimate of average 

risk and incidence. 

 

movement from one residence to another over the course of a 

lifetime.
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The assessments evaluate the cancer inhalation risks 

associated with continuous pollutant exposures over a 70-

year period, which is the assumed lifetime of an 

individual. In reality, both the length of time that 

modeled emissions sources at facilities actually operate 

(i.e., more or less than 70 years), and the domestic growth 

or decline of the modeled industry (i.e., the increase or 

decrease in the number or size of United States 

facilities), will influence the risks posed by a given 

source category. Depending on the characteristics of the 

industry, these factors will, in most cases, result in an 

overestimate both in individual risk levels and in the 

total estimated number of cancer cases. However, in rare 

cases, where a facility maintains or increases its emission 

levels beyond 70 years, residents live beyond 70 years at 

the same location, and the residents spend most of their 

days at that location, then the risks could potentially be 

underestimated. Annual cancer incidence estimates from 

exposures to emissions from these sources would not be 

affected by uncertainty in the length of time emissions 

sources operate. 

The exposure estimates used in these analyses assume 

chronic exposures to ambient levels of pollutants. Because 
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most people spend the majority of their time indoors, 

actual exposures may not be as high, depending on the 

characteristics of the pollutants modeled. For many of the 

HAP, indoor levels are roughly equivalent to ambient 

levels, but for very reactive pollutants or larger 

particles, these levels are typically lower. This factor 

has the potential to result in an overstatement of 25 to 30 

percent of exposures.

32

In addition to the uncertainties highlighted above, 

there are several factors specific to the acute exposure 

assessment that should be highlighted. The accuracy of an 

acute inhalation exposure assessment depends on the 

simultaneous occurrence of independent factors that may 

vary greatly, such as hourly emissions rates, meteorology, 

and human activity patterns. In this assessment, we assume 

that individuals remain for 1 hour at the point of maximum 

ambient concentration as determined by the co-occurrence of 

peak emissions and worst-case meteorological conditions. 

These assumptions would tend to overestimate actual 

exposures since it is unlikely that a person would be 

located at the point of maximum exposure during the time of 

worst-case impact.

 

32

U.S. EPA. National-Scale Air Toxics Assessment for 1996. (EPA 

453/R–01–003; January 2001; page 85.)
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iv. Uncertainties in Dose-Response Relationships

There are uncertainties inherent in the development of 

the dose-response values used in our risk assessments for 

cancer effects from chronic exposures and noncancer effects 

from both chronic and acute exposures. Some uncertainties 

may be considered quantitatively, and others generally are 

expressed in qualitative terms. We note as a preface to 

this discussion a point on dose-response uncertainty that 

is brought out in the EPA 2005 Cancer Guidelines; namely, 

that “the primary goal of the EPA actions is protection of 

human health; accordingly, as an Agency policy, risk 

assessment procedures, including default options that are 

used in the absence of scientific data to the contrary, 

should be health protective.” (EPA 2005 Cancer Guidelines, 

pages 1–7.) This is the approach followed here as 

summarized in the next several paragraphs. A complete 

detailed discussion of uncertainties and variability in 

dose-response relationships is given in the residual risk 

documentation, which is available in the docket for this 

action. 

Cancer URE values used in our risk assessments are 

those that have been developed to generally provide an 

upper bound estimate of risk. That is, they represent a 
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“plausible upper limit to the true value of a quantity” 

(although this is usually not a true statistical confidence 

limit).

33

In some circumstances, the true risk could be as 

low as zero; however, in other circumstances, the risk 

could also be greater.

34

When developing an upper bound 

estimate of risk and to provide risk values that do not 

underestimate risk, health-protective default approaches 

are generally used. To err on the side of ensuring adequate 

health-protection, the EPA typically uses the upper bound 

estimates rather than lower bound or central tendency 

estimates in our risk assessments, an approach that may 

have limitations for other uses (e.g., priority-setting or 

expected benefits analysis). 

Chronic noncancer reference (RfC and reference dose 

(RfD)) values represent chronic exposure levels that are 

intended to be health-protective levels. Specifically, 

these values provide an estimate (with uncertainty spanning 

perhaps an order of magnitude) of daily oral exposure (RfD) 

or of a continuous inhalation exposure (RfC) to the human 

population (including sensitive subgroups) that is likely 

 

33 IRIS glossary (http://www.epa.gov/NCEA/iris/help_gloss.htm).

34

An exception to this is the URE for benzene, which is 

considered to cover a range of values, each end of which is 

considered to be equally plausible and which is based on maximum 

likelihood estimates.
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to be without an appreciable risk of deleterious effects 

during a lifetime. To derive values that are intended to be 

“without appreciable risk,” the methodology relies upon an 

uncertainty factor (UF) approach (U.S. EPA, 1993, 1994) 

which includes consideration of both uncertainty and 

variability. When there are gaps in the available 

information, UF are applied to derive reference values that 

are intended to protect against appreciable risk of 

deleterious effects. The UF are commonly default values,

35

e.g., factors of 10 or 3, used in the absence of compoundspecific data; where data are available, UF may also be 

developed using compound-specific information. When data 

are limited, more assumptions are needed and more UF are 

used. Thus, there may be a greater tendency to overestimate 

 

35

According to the NRC report, Science and Judgment in Risk 

Assessment (NRC, 1994) “[Default] options are generic approaches, 

based on general scientific knowledge and policy judgment, that 

are applied to various elements of the risk assessment process 

when the correct scientific model is unknown or uncertain.” The 

1983 NRC report, Risk Assessment in the Federal Government: 

Managing the Process, defined default option as “the option 

chosen on the basis of risk assessment policy that appears to be 

the best choice in the absence of data to the contrary” (NRC, 

1983a, p. 63). Therefore, default options are not rules that bind 

the Agency; rather, the Agency may depart from them in evaluating 

the risks posed by a specific substance when it believes this to 

be appropriate. In keeping with EPA’s goal of protecting public 

health and the environment, default assumptions are used to 

ensure that risk to chemicals is not underestimated (although 

defaults are not intended to overtly overestimate risk). See EPA, 

2004, An Examination of EPA Risk Assessment Principles and 

Practices, EPA/100/B–04/001 available at:

http://www.epa.gov/osa/pdfs/ratf-final.pdf.
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risk in the sense that further study might support 

development of reference values that are higher (i.e., less 

potent) because fewer default assumptions are needed. 

However, for some pollutants, it is possible that risks may 

be underestimated. While collectively termed “uncertainty 

factor,” these factors account for a number of different 

quantitative considerations when using observed animal 

(usually rodent) or human toxicity data in the development 

of the RfC. The UF are intended to account for: (1) 

Variation in susceptibility among the members of the human 

population (i.e., inter-individual variability); (2) 

uncertainty in extrapolating from experimental animal data 

to humans (i.e., interspecies differences); (3) uncertainty 

in extrapolating from data obtained in a study with lessthan-lifetime exposure (i.e., extrapolating from subchronic to chronic exposure); (4) uncertainty in 

extrapolating the observed data to obtain an estimate of 

the exposure associated with no adverse effects; and (5) 

uncertainty when the database is incomplete or there are 

problems with the applicability of available studies. Many 

of the UF used to account for variability and uncertainty 

in the development of acute reference values are quite 

similar to those developed for chronic durations, but they 
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more often use individual UF values that may be less than 

10. UF are applied based on chemical-specific or health 

effect-specific information (e.g., simple irritation 

effects do not vary appreciably between human individuals, 

hence a value of 3 is typically used), or based on the 

purpose for the reference value (see the following 

paragraph). The UF applied in acute reference value 

derivation include: (1) Heterogeneity among humans; (2) 

uncertainty in extrapolating from animals to humans; (3) 

uncertainty in lowest observed adverse effect (exposure) 

level to no observed adverse effect (exposure) level 

adjustments; and (4) uncertainty in accounting for an 

incomplete database on toxic effects of potential concern. 

Additional adjustments are often applied to account for 

uncertainty in extrapolation from observations at one 

exposure duration (e.g., 4 hours) to derive an acute 

reference value at another exposure duration (e.g., 1 

hour). 

Not all acute reference values are developed for the 

same purpose and care must be taken when interpreting the 

results of an acute assessment of human health effects 

relative to the reference value or values being exceeded. 

Where relevant to the estimated exposures, the lack of
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short-term dose-response values at different levels of 

severity should be factored into the risk characterization 

as potential uncertainties. 

Although every effort is made to identify peerreviewed reference values for cancer and noncancer effects 

for all pollutants emitted by the sources included in this 

assessment, some HAP continue to have no reference values 

for cancer or chronic noncancer or acute effects. Since 

exposures to these pollutants cannot be included in a 

quantitative risk estimate, an understatement of risk for 

these pollutants at environmental exposure levels is 

possible. For a group of compounds that are either 

unspeciated or do not have reference values for every 

individual compound (e.g., glycol ethers), we 

conservatively use the most protective reference value to 

estimate risk from individual compounds in the group of 

compounds. 

Additionally, chronic reference values for several of 

the compounds included in this assessment are currently 

under the EPA IRIS review and revised assessments may 

determine that these pollutants are more or less potent 

than the current value. We may re-evaluate residual risks 

for the final rulemaking if these reviews are completed 
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prior to our taking final action for these source 

categories and a dose-response metric changes enough to 

indicate that the risk assessment supporting this notice 

may significantly understate human health risk.

v. Uncertainties in the Multi-Pathway and Environmental 

Effects Assessment

We generally assume that when exposure levels are not 

anticipated to adversely affect human health, they also are 

not anticipated to adversely affect the environment. For 

each source category, we generally rely on the sitespecific levels of PB-HAP emissions to determine whether a 

full assessment of the multi-pathway and environmental 

effects is necessary. As discussed above, we conclude that 

the potential for these types of impacts is low for these 

source categories.

vi. Uncertainties in the Facility-Wide Risk Assessment

Given that the same general analytical approach and 

the same models were used to generate facility-wide risk 

results as were used to generate the source category risk 

results, the same types of uncertainties discussed above 

for our source category risk assessments apply to the 

facility-wide risk assessments. Additionally, the degree of 

uncertainty associated with facility-wide emissions and 
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risks is likely greater because we generally have not 

conducted a thorough engineering review of emissions data 

for source categories not currently undergoing an RTR 

review. 

vii. Uncertainties in the Demographic Analysis

Our analysis of the distribution of risks across 

various demographic groups is subject to the typical 

uncertainties associated with census data (e.g., errors in 

filling out and transcribing census forms), as well as the 

additional uncertainties associated with the extrapolation 

of census-block group data (e.g., income level and 

education level) down to the census block level.

2. What are the results and proposed decisions from the 

risk review for the Oil and Natural Gas Production source 

category?

a. Results of the Risk Assessments and Analyses

We conducted an inhalation risk assessment for the Oil 

and Natural Gas Production source category. We also 

conducted an assessment of facility-wide risk. Details of 

the risk assessments and analyses can be found in the 

residual risk documentation, which is available in the 

docket for this action. For informational purposes and to 

examine the potential for any EJ issues that might be 
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associated with each source category, we performed a 

demographic analysis of population risks.

i. Inhalation Risk Assessment Results

Table 2 provides an overall summary of the results of 

the inhalation risk assessment. 

TABLE 2. OIL AND NATURAL GAS PRODUCTION INHALATION RISK 

ASSESSMENT RESULTS

Number of 

Facilities

1

Maximum

Individual

Cancer Risk

(in 1 million)2

Estimated 

Population

at Risk ≥ 

1-in-1 

Million

Estimated 

Annual

Cancer

Incidence 

(cases 

per year)

Maximum

Chronic Noncancer

TOSHI4

Maximum 

OffSite 

Acute

Noncanc

er HQ5

Actual 

Emissions 

Level

Allowable 

Emissions 

Level

Actual 

Emissions 

Level

Allowable 

Emissions 

Level

990 40

100 -

4003 160,0003

0.007 -

0.023

0.1 0.7

HQREL = 

9

(benzen

e)

HQAEGL-1

= 0.07 

(benzen

e)

1 Number of facilities evaluated in the risk analysis.

2 Estimated maximum individual excess lifetime cancer risk.

3 The EPA IRIS assessment for benzene provides a range of 

equally-plausible URE (2.2E-06 to 7.8E-06 per ug/m3), 

giving rise to ranges for the estimates of cancer MIR and 

cancer incidence. Estimated population values are not 

scalable with benzene URE range, but would be lower using 

the lower end of the URE range.

4 Maximum TOSHI. The target organ with the highest TOSHI 

for the Oil and Natural Gas Production source category is 

the respiratory system. 

5 The maximum estimated acute exposure concentration was 

divided by available short-term dose-response values to 

develop an array of HQ values. 

As shown in Table 2, the results of the inhalation 

risk assessment performed using actual emissions data 

indicate the maximum lifetime individual cancer risk could 
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be as high as 40-in-1 million, with POM driving the highest 

risk, and benzene driving risks overall. The total 

estimated cancer incidence from this source category is 

0.02 excess cancer cases per year (0.007 excess cancer 

cases per year based on the lower end of the benzene URE 

range), or one case in every 50 years. Approximately 

160,000 people are estimated to have cancer risks at or 

above 1-in-1 million as a result of the emissions from 89 

facilities (use of the lower end of the benzene URE range 

would further reduce this population estimate). The maximum 

chronic non-cancer TOSHI value for the source category 

could be up to 0.1 from emissions of naphthalene, 

indicating no significant potential for chronic noncancer 

impacts.

As explained above, our analysis of potential 

differences between actual emission levels and emissions 

allowable under the oil and natural gas production MACT 

standard indicate that MACT-allowable emission levels may 

be up to 50 times greater than actual emission levels. 

Considering this difference, the risk results from the 

inhalation risk assessment indicate the maximum lifetime 

individual cancer risk could be as high as 400-in-1 million

(100-in-1 million based on the lower end of the benzene URE 
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range) and the maximum chronic noncancer TOSHI value could 

be as high as 0.7 at the MACT-allowable emissions level. 

ii. Facility-Wide Risk Assessment Results

A facility-wide risk analysis was also conducted based 

on actual emissions levels. Table 3 displays the results of 

the facility-wide risk assessment. For detailed facilityspecific results, see Table 2 of Appendix 6 of the risk 

document in the docket for this rulemaking. 

TABLE 3. OIL AND NATURAL GAS PRODUCTION FACILITY-WIDE RISK 

ASSESSMENT RESULTS

Number of facilities analyzed 990

Cancer 

Risk

Estimated maximum facility-wide 

individual cancer risk (in 1 million) 100

Number of facilities with estimated 

facility-wide individual cancer risk 

of 100-in-1 million or more

1

Number of facilities at which the Oil 

and Natural Gas Production source 

category contributes 50 percent or 

more to the facility-wide individual 

cancer risks of 100-in-1 million or 

more

0

Number of facilities with facilitywide individual cancer risk of 1-in-1 

million or more

140

Number of facilities at which the Oil 

and Natural Gas Production source 

category contributes 50 percent or 

more to the facility-wide individual 

cancer risk of 1-in-1 million or more

85

Chronic 

Noncancer 

Risk

Maximum facility-wide chronic 

noncancer TOSHI 9

Number of facilities with facilitywide maximum noncancer TOSHI greater 

than 1

10
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Number of facilities at which the Oil 

and Natural Gas Production source 

category contributes 50 percent or 

more to the facility-wide maximum 

noncancer TOSHI of 1 or more

0

The facility-wide MIR from all HAP emissions at a 

facility that contains sources subject to the oil and 

natural gas production MACT standards is estimated to be 

100-in-1 million, based on actual emissions. Of the 990 

facilities included in this analysis, only one has a 

facility-wide MIR of 100-in-1 million. At this facility, 

oil and natural gas production accounts for less than 2 

percent of the total facility-wide risk. Nickel emissions 

from oil-fired boilers and formaldehyde emissions from 

reciprocating internal combustion engines (RICE) contribute 

essentially all the facility-wide risks at this facility, 

with over 80 percent of the risk attributed to the nickel 

emissions.36 There are 140 facilities with facility-wide MIR 

of 1-in-1 million or greater. Of these facilities, 85 have 

oil and natural gas production operations that contribute 

greater than 50 percent to the facility-wide risks. As 

discussed above, we are proposing MACT standards for BTEX 

 

36 We note that there is an ongoing IRIS reassessment for 

formaldehyde, and that future RTR risk assessments will use the 

cancer potency for formaldehyde that results from that 

reassessment. As a result, the current results may not match 

those of future assessments.
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emissions from small glycol dehydrators in this action. 

These standards would reduce the risk from benzene 

emissions at facilities with oil and gas production. 

Formaldehyde emissions will be assessed under future RTR 

for RICE.

The facility-wide maximum individual chronic noncancer 

TOSHI is estimated to be 9 based on actual emissions. Of 

the 990 facilities included in this analysis, 10 have 

facility-wide maximum chronic noncancer TOSHI values 

greater than 1. Of these facilities, none had oil and 

natural gas production operations that contributed greater 

than 50 percent to these facility-wide risks. The chronic 

noncancer risks at these 10 facilities are primarily driven 

by acrolein emissions from RICE. 

iii. Demographic Risk Analysis Results

The results of the demographic analyses performed to 

investigate the distribution of cancer risks at or above 1-

in-1 million among the surrounding population are 

summarized in Table 4 below. These results, for various 

demographic groups, are based on actual emissions levels 

for the population living within 50 km of the facilities. 

TABLE 4. OIL AND NATURAL GAS PRODUCTION DEMOGRAPHIC RISK 

ANALYSIS RESULTS

Nationwide

Population with Cancer Risk at 

or Above 1-in-1 Million Due 
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to.... 

Source Category 

HAP Emissions

Facility-Wide 

HAP Emissions

Total 

Population

285,000,000 160,000 597,000

Race by Percent

White 75 62 61

All Other 

Races 25 38 39

Race by Percent

White 75 62 61

African 

American 12 12 8

Native 

American 0.9 0.7 1.3

Other and 

Multiracial 12 25 30

Ethnicity by Percent

Hispanic 14 22 34

Non-Hispanic 86 78 66

Income by Percent

Below Poverty 

Level 13 14 19

Above Poverty 

Level 87 86 81

Education by Percent

Over 25 and 

without High 

School 

Diploma

13 10 16

Over 25 and 

with a High 

School 

Diploma

87 90 84

The results of the Oil and Natural Gas Production 

source category demographic analysis indicate that there 

are approximately 160,000 people exposed to a cancer risk 

at or above 1-in-1 million due to emissions from the source 

category, including an estimated 38 percent that are 
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classified as minority (listed as “All Other Races” in the 

table above). Of the 160,000 people with estimated cancer 

risks at or above 1-in-1 million from the source category, 

25 percent are in the “Other and Multiracial” demographic 

group, 22 percent are in the “Hispanic or Latino” 

demographic group, and 14 percent are in the “Below Poverty 

Level” demographic group, results which are 13, 8 and 1 

percentage points higher, respectively, than the respective 

percentages for these demographic groups across the United 

States. The percentages for the other demographic groups 

are lower than their respective nationwide percentages. The 

table also shows that there are approximately 597,000 

people exposed to an estimated cancer risk at or above 1-

in-1 million due to facility-wide emissions, including 30 

percent in the “Other and Multiracial” demographic group, 

34 percent in the “Hispanic or Latino” demographic group, 

1.3 percent in the “Native American” demographic group and 

16 percent in the “Over 25 and without High School Diploma” 

demographic group, results which are 18, 2, 0.4 and 3 

percentage points higher than the percentages for these 

demographic groups across the United States, respectively. 

The percentages for the other demographic groups are lower 

than their respective nationwide percentages.
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b. What are the proposed risk decisions for the Oil and 

Natural Gas Production source category?

i. Risk Acceptability

In the risk analysis we performed for this source 

category, pursuant to CAA section 112(f)(2), we considered 

the available health information--the MIR; the numbers of 

persons in various risk ranges; cancer incidence; the 

maximum noncancer HI; the maximum acute noncancer hazard; 

the extent of noncancer risks; the potential for adverse 

environmental effects; and distribution of risks in the 

exposed population; and risk estimation uncertainty (54 FR 

38044, September 14, 1989). 

For the Oil and Natural Gas Production source 

category, the risk analysis we performed indicates that the 

cancer risks to the individual most exposed could be as 

high as 40-in-1 million due to actual emissions and as high 

as 400-in-1 million due to MACT-allowable emissions (100-

in-1 million, based on the lower end of the benzene URE 

range). While the 40-in-1 million risk due to actual 

emissions is considerably less than 100-in-1 million, which 

is the presumptive limit of acceptability, the 400-in-1

million risk due to allowable emissions is considerably 

higher and is considered unacceptable. We do note, however, 
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that the risk analysis shows low cancer incidence (1 case 

in every 50 years), low potential for adverse environmental 

effects or human health multi-pathway effects and that 

chronic noncancer health impacts are unlikely.

We also conclude that acute noncancer health impacts 

are unlikely. As discussed above, screening estimates of 

acute exposures and risks were evaluated for each of the 

HAP at the point of highest off-site exposure for each 

facility (i.e., not just the census block centroids) 

assuming that a person is located at this spot at a time 

when both the peak emission rate and worst-case dispersion 

conditions occur. Under these worst-case conditions, we 

estimate benzene acute HQ values (based on the REL) could 

be as high as 9. Although the REL (which indicates the 

level below which adverse effects are not anticipated) is 

exceeded in this case, we believe the potential for acute 

effects is low for several reasons. First, the acute 

modeling scenario is worst-case because of the confluence 

of peak emission rates and worst-case dispersion 

conditions. Second, the benzene REL is based on a 6-hour 

exposure duration because a 1-hour exposure duration value 

was unavailable. An REL based on a 6-hour exposure duration 

is generally lower than an REL based on a 1-hour exposure 
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duration and, consequently, easier to exceed. Also, 

although there are exceedances of the REL, the highest 

estimated 1-hour exposure is less than 10 percent of the 

AEGL-1 value, which is a level at which effects could be 

experienced. Finally, the generally sparse populations near 

these facilities make it less likely that a person would be 

near the plant to be exposed. For example, in the two cases 

where the acute HQ value is as high as 9, there are only 30 

people associated with the census blocks within 2 miles of 

the two facilities. 

While our additional analysis of facility-wide risks 

showed that there is one facility with maximum facilitywide cancer risk of 100-in-1 million or greater and 10 

facilities with a maximum chronic noncancer TOSHI greater 

than 1, it also showed that oil and natural gas production 

operations did not drive these risks. 

In determining whether risk is acceptable, we 

considered the available health information, as described 

above. In this case, although a number of factors we 

considered indicate relatively low risk concern, we are 

proposing to determine that the risks are unacceptable, in 

large part, because the MIR is 400-in-1 million due to 

MACT-allowable emissions, which greatly exceeds the 
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“presumptive limit on maximum individual lifetime risk of 

approximately 1-in-10 thousand [100-in-1 million] 

recognized in the Benzene NESHAP (54 FR 38045).” The MIR,

based on MACT-allowable emissions, is driven by the 

allowable emissions of 0.9 Mg/yr benzene under the MACT as 

a compliance option. We are, therefore, proposing to 

eliminate the alternative compliance option of 0.9 Mg/yr

benzene from the existing glycol dehydrator MACT 

requirements. With this change, the source category MIR,

based on MACT-allowable emissions, would be reduced to 40-

in-1 million, which we find acceptable in light of all the 

other factors considered. Thus, we are proposing that the 

risks from the Oil and Natural Gas Production source 

category are acceptable, with the removal of the 

alternative compliance option of 0.9 Mg/yr benzene limit 

from the current glycol dehydrator MACT requirements.

Pursuant to CAA section 112(f)(4), we are proposing 

that this change (i.e., removal of the 0.9 Mg/yr compliance 

alternative) apply 90 days after its effective date. We are 

requesting comment on whether or not this is sufficient 

time for the large dehydrators that have been relying on 

this compliance alternative to come into compliance with 

the 95-percent control requirement or if additional time is 
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needed. See CAA section 112(f)(4)(A). 

We recognize that our proposal to remove the 0.9 Mg/yr

compliance alternative for the 95-percent control glycol 

dehydrator MACT standard could have negative impacts on 

some sources that have come to rely on the flexibility this 

alternative provides. We solicit comment on any such 

impacts and whether such impacts warrant adding a different 

compliance alternative that would result in less risk than 

the 0.9 Mg/yr benzene limit compliance option. If a 

commenter suggests a different compliance alternative, the 

commenter should explain, in detail, what that alternative 

would be, how it would work and how it would reduce risk.

ii. Ample Margin of Safety

We next considered whether this revised standard 

(existing MACT plus removal of 0.9 Mg/yr benzene compliance 

option) provides an ample margin of safety. In this 

analysis, we investigated available emissions control 

options that might reduce the risk associated with 

emissions from the source category and considered this 

information along with all of the health risks and other 

health information considered in the risk acceptability 

determination. 

For glycol dehydrators, we considered the addition of 
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a second control device in the same manner that was 

discussed in the floor evaluation in section VII.B.1 above. 

The cost effectiveness associated with that option would be 

$167,200/Mg, which we believe is too high to require 

additional controls on glycol dehydrators.

Similarly, we considered the addition of a second 

control device to the required MACT floor control device 

(cost effectiveness of $18,300/Mg). Similar to our 

discussion of beyond-the-MACT-floor controls for glycol

dehydrators in section VII.B.1 of this preamble, the 

incremental cost to add a second control device for storage 

vessels would be approximately 20 times higher than the 

MACT floor cost effectiveness, or $366,000/Mg. We do not 

believe this cost effectiveness is reasonable.

For leak detection, we considered implementation of 

LDAR programs that are more stringent than the current 

standards. An assessment performed for various LDAR options 

under the NSPS in section VI.B.4.b of this preamble yielded 

the lowest cost effectiveness of $5,170/Mg ($4,700/ton) for 

control of VOC for the options evaluated. A LDAR program to 

control HAP would involve similar costs for equipment, 

labor, etc., to those considered in the NSPS assessment, 

but since there is approximately 20 times less HAP than VOC 
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present in material handled in regulated equipment, the 

cost effectiveness to control HAP would be approximately 20 

times greater (i.e., $100,000/Mg) for HAP, which we believe 

is not reasonable. 

In accordance with the approach established in the 

Benzene NESHAP, the EPA weighed all health risk measures 

and information considered in the risk acceptability 

determination, along with the costs and economic impacts of 

emissions controls, technological feasibility, 

uncertainties and other relevant factors in making our 

ample margin of safety determination. Considering the 

health risk information and the high cost effectiveness of 

the options identified, we propose that the existing MACT 

standards, with the removal of the 1 tpy benzene limit 

compliance option from the glycol dehydrator standards, 

provide an ample margin of safety to protect public health.

While we are proposing that the oil and natural gas 

production MACT standards (with the removal of the 

alternative compliance option of 1 tpy benzene limit) 

provide an ample margin of safety to protect public health, 

we are concerned about the estimated facility-wide risks 

identified through these screening analyses. As described 

previously, the highest estimated facility-wide cancer 
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risks are mostly due to emissions from oil fired boilers 

and RICE. Both of these sources are regulated under other 

source categories and we anticipate that emission 

reductions from those sources will occur as standards for 

those source categories are implemented.

3. What are the results and proposed decisions from the 

risk review for the Natural Gas Transmission and Storage 

source category?

a. Results of the Risk Assessments and Analyses

We conducted an inhalation risk assessment for the 

Natural Gas Transmission and Storage source category. We 

also conducted an assessment of facility-wide risk and 

performed a demographic analysis of population risks. 

Details of the risk assessments and analyses can be found 

in the residual risk documentation, which is available in 

the docket for this action.

i. Inhalation Risk Assessment Results

Table 5 provides an overall summary of the results of 

the inhalation risk assessment. For informational purposes 

and to examine the potential for any EJ issues that might 

be associated with each source category, we performed a 

demographic analysis of population risks.

TABLE 5. NATURAL GAS TRANSMISSION AND STORAGE INHALATION 

RISK ASSESSMENT RESULTS
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Number of 

Facilities

1

Maximum

Individual

Cancer Risk

(in 1 million)2

Estimated 

Population

at Risk ≥ 

1-in-1 

Million

Estimated 

Annual

Cancer

Incidence 

(cases 

per year)

Maximum

Chronic Noncancer

TOSHI4

Maximum 

OffSite 

Acute 

Noncanc

er HQ5

Actual 

Emissions 

Level

Allowable 

Emissions 

Level

Actual 

Emissions 

Level

Allowable 

Emissions 

Level

321 30 - 903 30 - 903 2,5003

0.0003 -

0.0013

0.4 0.8

HQREL = 

5

(benzen

e)

HQAEGL-1

= 0.2 

(chloro

benzene

)

1 Number of facilities evaluated in the risk analysis.

2 Estimated maximum individual excess lifetime cancer risk.

3 The EPA IRIS assessment for benzene provides a range of 

equally-plausible URE (2.2E-06 to 7.8E-06 per ug/m3), 

giving rise to ranges for the estimates of cancer MIR and 

cancer incidence. Estimated population values are not 

scalable with benzene URE range, but would be lower using 

the lower end of the URE range.

4 Maximum TOSHI. The target organ with the highest TOSHI 

for the Natural Gas Transmission and Storage source 

category is the immune system. 

5 The maximum estimated acute exposure concentration was 

divided by available short-term dose-response values to 

develop an array of HQ values. 

As shown in Table 5 above, the results of the 

inhalation risk assessment performed using actual emissions 

data indicate the maximum lifetime individual cancer risk 

could be as high as 90-in-1 million, (30-in-1 million based 

on the lower end of the benzene URE range), with benzene as 

the major contributor to the risk. The total estimated 

cancer incidence from the source category is 0.001 excess 

cancer cases per year (0.0003 excess cancer cases per year 

based on the lower end of the benzene URE range), or one 
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case in every polycyclic organic matter 1,000 years. 

Approximately 2,500 people are estimated to have cancer 

risks at or above 1-in-1 million as a result of the 

emissions from 15 facilities (use of the lower end of the 

benzene URE range would further reduce this population 

estimate). The maximum chronic noncancer TOSHI value for 

the source category could be up to 0.4 from emissions of 

benzene, indicating no significant potential for chronic 

noncancer impacts.

As explained above in section VII.C.1.b, our analysis 

of potential differences between actual emission levels and 

emissions allowable under the natural gas transmission and 

storage MACT standard indicate that MACT-allowable emission 

levels may be up to 50 times greater than actual emission 

levels at some sources. However, because some sources are 

emitting at the level allowed under the current NESHAP, the 

risk results from the inhalation risk assessment indicate 

the maximum lifetime individual cancer risk would still be 

90-in-1 million (30-in-1 million based on the lower end of 

the benzene URE range), based on both actual and allowable 

emission levels, and the maximum chronic noncancer TOSHI 

value could be as high as 0.8 at the MACT-allowable 

emissions level. 
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ii. Facility-Wide Risk Assessment Results

A facility-wide risk analysis was also conducted based 

on actual emissions levels. Table 6 below displays the 

results of the facility-wide risk assessment. For detailed 

facility-specific results, see Table 2 of Appendix 6 of the 

risk document in the docket for this rulemaking. 

TABLE 6. NATURAL GAS TRANSMISSION AND STORAGE FACILITY-WIDE 

RISK ASSESSMENT RESULTS

Number of Facilities Analyzed 321

Cancer 

Risk

Estimated maximum facility-wide 

individual cancer risk (in 1 million) 2001

Number of facilities with estimated 

facility-wide individual cancer risk 

of 100-in-1 million or more

3

Number of facilities at which the 

Natural Gas Transmission and Storage 

source category contributes 50 percent 

or more to the facility-wide 

individual cancer risks of 100-in-1 

million or more

1

Number of facilities with facilitywide individual cancer risk of 1-in-1 

million or more

74

Number of facilities at which the 

Natural Gas Transmission and Storage 

source category contributes 50 percent 

or more to the facility-wide 

individual cancer risk of 1-in-1 

million or more

10

Chronic 

Noncancer 

Risk

Maximum facility-wide chronic 

noncancer TOSHI 80

Number of facilities with facilitywide maximum noncancer TOSHI greater 

than 1

30

Number of facilities at which the 

Natural Gas Transmission and Storage 

source category contributes 50 percent 

0
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or more to the facility-wide maximum 

noncancer TOSHI of 1 or more

1

We note that the MIR would be 100-in-1 million if the CIIT URE 

for formaldehyde were used instead of the IRIS URE.

The facility-wide MIR from all HAP emissions at any 

facility that contains sources subject to the natural gas 

transmission and storage MACT standards is estimated to be 

200-in-1 million, based on actual emissions. Of the 321 

facilities included in this analysis, three have facilitywide MIR of 100-in-1 million or greater. The facility-wide 

MIR is 200-in-1 million at two of these facilities, driven 

by formaldehyde from RICE.37 Another facility has a 

facility-wide risk of 100-in-1 million, with 90 percent of 

the risk attributed to natural gas transmission and 

storage. There are 74 facilities with facility-wide MIR of 

1-in-1 million or greater. Of these facilities, 10 have 

natural gas transmission and storage operations that 

contribute greater than 50 percent to the facility-wide 

risks. As discussed above, we are proposing MACT standards 

for benzene emissions from small glycol dehydrators in this 

action. These standards would reduce the risk from benzene 

emissions at facilities with natural gas transmission and 

 

37 We note that there is an ongoing IRIS reassessment for 

formaldehyde, and that future RTR risk assessments will use the 

cancer potency for formaldehyde that results from that 

reassessment. As a result, the current results may not match 

those of future assessments.
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storage operations. The facility-wide cancer risks at the

facilities with risks of 1-in-1 million or more are 

primarily driven by formaldehyde emissions from RICE, which 

will be assessed in a future RTR for that category. 

The facility-wide maximum individual chronic noncancer 

TOSHI is estimated to be 80, based on actual emissions. Of 

the 321 facilities included in this analysis, 30 have 

facility-wide maximum chronic noncancer TOSHI values 

greater than 1. Of these facilities, none had natural gas 

transmission and storage operations that contributed 

greater than 50 percent to these facility-wide risks. The 

chronic noncancer risks at these facilities are primarily 

driven by acrolein emissions from RICE. 

iii. Demographic Risk Analysis Results

The results of the demographic analyses performed to 

investigate the distribution of cancer risks at or above 1-

in-1 million among the surrounding population are 

summarized in Table 7 below. These results, for various 

demographic groups, are based on actual emissions levels 

for the population living within 50 km of the facilities. 

TABLE 7. NATURAL GAS TRANSMISSION AND STORAGE DEMOGRAPHIC 

RISK ANALYSIS RESULTS

Nationwide

Population with Cancer Risk at 

or Above 1-in-1 Million Due 

to.... 

Source Category Facility-Wide 
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HAP Emissions HAP Emissions

Total 

Population

285,000,000 2,500 99,000

Race by Percent

White 75 92 58

All Other 

Races 25 8 42

Race by Percent

White 75 92 58

African 

American 12 6 40

Native 

American 0.9 0.1 0.2

Other and 

Multiracial 12 1 2

Ethnicity by Percent

Hispanic 14 1 2

Non-Hispanic 86 99 98

Income by Percent

Below Poverty 

Level 13 17 20

Above poverty 

level 87 83 80

Education by Percent

Over 25 and 

without High 

School 

Diploma

13 20 15

Over 25 and 

with a High 

School 

Diploma

87 80 85

The results of the Natural Gas Transmission and 

Storage source category demographic analysis indicate that 

there are approximately 2,500 people exposed to a cancer 

risk at or above 1-in-1 million due to emissions from the 

source category, including an estimated 8 percent that are 

classified as minority (listed as “All Other Races” in 
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Table 7 above). Of the 2,500 people with estimated cancer 

risks at or above 1-in-1 million from the source category, 

17 percent are in the “Below Poverty Level” demographic 

group, and 20 percent are in the “Over 25 and without High 

School Diploma” demographic group, results which are 4 and 

7 percentage points higher, respectively, than the 

percentages for these demographic groups across the United 

States. The percentages for the other demographic groups 

are lower than their respective nationwide percentages. The 

table also shows that there are approximately 99,000 people 

exposed to an estimated cancer risk at or above 1-in-1 

million due to facility-wide emissions, including an 

estimated 42 percent that are classified as minority (“All 

Other Races” in Table 7 above). Of the 99,000 people with 

estimated cancer risk at or above 1-in-1 million from 

facility-wide emissions, 40 percent are in the “African 

American” demographic group, 20 percent are in the “Below 

Poverty Level” demographic group, and 15 percent are in the 

“Over 25 and without High School Diploma” demographic

group, results which are 28, 7 and 2 percentage points 

higher, respectively, than the percentages for these 

demographic groups across the United States. The 

percentages for the other demographic groups are equal to 
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or lower than their respective nationwide percentages. 

b. What are the proposed risk decisions for the Natural Gas 

Transmission and Storage source category?

i. Risk Acceptability

In the risk analysis we performed for this source 

category, pursuant to CAA section 112(f)(2), we considered 

the available health information--the MIR; the numbers of 

persons in various risk ranges; cancer incidence; the 

maximum noncancer HI; the maximum acute noncancer hazard; 

the extent of noncancer risks; the potential for adverse 

environmental effects; distribution of risks in the exposed 

population; and risk estimation uncertainty (54 FR 38044, 

September 14, 1989). 

For the Natural Gas Transmission and Storage source 

category, the risk analysis we performed indicates that the 

cancer risks to the individual most exposed could be as 

high as 90-in-1 million due to actual and allowable 

emissions (30-in-1 million, based on the lower end of the 

benzene URE range). These risks are near 100-in-1 million, 

which is the presumptive limit of acceptability. On the 

other hand, the risk analysis shows low cancer incidence (1 

case in every 1,000 years), low potential for adverse 

environmental effects or human health multi-pathway effects
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and that chronic and acute noncancer health impacts are 

unlikely. We conclude that acute noncancer health impacts 

are unlikely for reasons similar to those described in 

section VII.C.2.b.i of this preamble. 

Our additional analysis of facility-wide risks showed 

that, among three facilities with maximum facility-wide 

cancer risk of 100-in-1 million or greater, one facility 

has a facility-wide cancer risk of 100-in-1 million, with 

90 percent of the risk attributed to natural gas and 

transmission and storage. There are 30 facilities with a 

maximum chronic noncancer TOSHI greater than 1, but natural 

gas transmission and storage operations did not drive this

risk. 

In determining whether risk is acceptable, we 

considered the available health information, as described 

above. In this case, because the MIR is approaching, but 

still less than 100-in-1 million risk, and because a number 

of other factors indicate relatively low risk concern

(e.g., low cancer incidence, low potential for adverse 

environmental effects or human health multi-pathway 

effects, chronic and acute noncancer health impacts 

unlikely), we are proposing to determine that the risks are 

acceptable.
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ii. Ample Margin of Safety

We next considered whether the existing MACT standard

provides an ample margin of safety. In this analysis, we 

investigated available emissions control options that might 

reduce the risk associated with emissions from the source 

category and considered this information, along with all of 

the health risks and other health information considered in 

the risk acceptability determination. The estimated MIR of 

90-in-1 million discussed above is driven by the 0.9 

Mg/year benzene limit compliance alternative for the glycol 

dehydrator MACT standard in the current NESHAP. Removal of 

this compliance alternative would lower the MIR for the 

source category to 20-in-1 million. We, therefore, 

considered removing this compliance alternative as an 

option for reducing risk and assessed the cost of such 

alternative. Without the compliance alternative, affected 

glycol dehydrators (i.e., those units with annual average 

benzene emissions of 0.9 Mg/yr or greater and an annual 

average natural gas throughput of 283,000 scmd or greater) 

must demonstrate compliance with the 95-percent control 

requirement, which we believe can be shown with their 

existing control devices in most cases, although, in some 

instances, installation of a different or an additional 
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control may be necessary. 

In section VII.B.1 above, we discuss the costs for 

requiring controls on currently unregulated “small glycol 

dehydrators,” which are similar, in operation and type of 

emission controls, to the dehydrators subject to the 

current MACT (“large dehydrators”). The HAP cost 

effectiveness determined for small dehydrators at the floor 

level of control was $1,650/Mg. Although control 

methodologies are similar for large and small dehydrators, 

we expect that the costs for controls on large units could 

be as much as twice as high as for small units because of 

the large gas flow being processed. However, we also expect 

that the amount of HAP emission reduction for the large 

dehydrators, in general, to be as much as, or more than, 

the amount achieved by small dehydrators. In light of the 

above, we do not expect the cost effectiveness of the 

control device needed to meet the 95-percent control 

requirement for large dehydrators to exceed $3,300/Mg 

(i.e., twice the cost effectiveness for small dehydrators), 

which we consider to be reasonable. 

In accordance with the approach established in the 

Benzene NESHAP, the EPA weighed all health risk measures 

and information considered in the risk acceptability 
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determination, along with the costs and economic impacts of 

emissions controls, technological feasibility, 

uncertainties and other relevant factors in making our 

ample margin of safety determination. Considering the 

health risk information and the reasonable cost 

effectiveness of the option identified, we propose that the

existing MACT standards, with the removal of the 0.9 Mg 

benzene limit compliance option from the glycol dehydrator 

standards, provide an ample margin of safety to protect 

public health.

Pursuant to CAA section 112(f)(4), we are proposing 

that this change (i.e., removal of the 0.9 Mg/yr compliance 

alternative) apply 90 days after its effective date. We are 

requesting comment on whether or not there is sufficient 

time for the large dehydrators that have been relying on 

this compliance alternative to come into compliance with 

the 95-percent control requirement or if additional time is 

needed. See CAA section 112(f)(4)(A).

We recognize that our proposal to remove the one-ton 

compliance alternative for the 95-percent control glycol 

dehydrator MACT standard could have negative impacts on 

some sources that have come to rely on the flexibility this 

alternative provides. We solicit comment on any such 
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impacts and whether such impacts warrant adding a different 

compliance alternative that would result in less risk than 

the 0.9 Mg/yr benzene limit compliance option. If a 

commenter suggests a different compliance alternative, the 

commenter should explain, in detail, what that alternative 

would be, how it would work, and how it would reduce risk.

As described above, we are proposing that the natural 

gas transmission and storage MACT standards (with the 

removal of the 0.9 Mg/yr benzene limit compliance option) 

provide an ample margin of safety to protect public health. 

We recognize that one facility has a facility-wide cancer 

risk of 100-in-1 million, with 90 percent of the risk 

attributed to natural gas transmission and storage. This 

risk is driven by benzene emissions from glycol dehydrators 

and is being addressed by our proposed revision to the 

Natural Gas Transmission and Storage NESHAP (removal of the 

0.9 Mg/yr benzene limit compliance option). As previously 

mentioned, two facilities have facility-wide MIR of 200-in1 million, driven by formaldehyde from RICE. Emissions from 

RICE are regulated under another source category and will 

be assessed under a future RTR for that category.

D. How did we perform the technology review and what are 

the results and proposed decisions?
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1. What was the methodology for the technology review?

Our technology review is focused on the identification 

and evaluation of “developments in practices, processes, 

and control technologies” since the promulgation of the 

MACT standards for the two oil and gas source categories. 

If a review of available information identifies such 

developments, then we conduct an analysis of the technical 

feasibility of requiring the implementation of these 

developments, along with the impacts (costs, emission 

reductions, risk reductions, etc.). We then make a decision 

on whether it is necessary to amend the regulation to 

require these developments.

Based on specific knowledge of each source category, 

we began by identifying known developments in practices, 

processes and control technologies. For the purpose of this 

exercise, we considered any of the following to be a 

“development”:

• Any add-on control technology or other equipment that 

was not identified and considered during MACT 

development;

• Any improvements in add-on control technology or other 

equipment (that was identified and considered during 

MACT development) that could result in significant 
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additional emission reduction;

• Any work practice or operational procedure that was 

not identified and considered during MACT development; 

and

• Any process change or pollution prevention alternative 

that could be broadly applied that was not identified 

and considered during MACT development.

In addition to looking back at practices, processes or 

control technologies reviewed at the time we developed the 

MACT standards, we reviewed a variety of sources of data to 

aid in our evaluation of whether there were additional 

practices, processes or controls to consider. One of these 

sources of data was subsequent air toxics rules. Since the 

promulgation of the MACT standards for the source 

categories addressed in this proposal, the EPA has 

developed air toxics regulations for a number of additional 

source categories. We reviewed the regulatory requirements 

and/or technical analyses associated with these subsequent 

regulatory actions to identify any practices, processes and 

control technologies considered in these efforts that could 

possibly be applied to emission sources in the source 

categories under this current RTR review.

We also consulted the EPA’s RBLC. The terms "RACT," 
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"BACT," and "LAER" are acronyms for different program 

requirements under the CAA provisions addressing the NAAQS. 

Control technologies classified as RACT, BACT or LAER apply 

to stationary sources depending on whether the source 

exists or is new and on the size, age and location of the 

facility. The BACT and LAER (and sometimes RACT) are 

determined on a case-by-case basis, usually by state or 

local permitting agencies. The EPA established the RBLC to 

provide a central database of air pollution technology 

information (including technologies required in sourcespecific permits) to promote the sharing of information 

among permitting agencies and to aid in identifying future 

possible control technology options that might apply 

broadly to numerous sources within a category or apply only 

on a source-by-source basis. The RBLC contains over 5,000 

air pollution control permit determinations that can help 

identify appropriate technologies to mitigate many air 

pollutant emission streams. We searched this database to 

determine whether any practices, processes or control 

technologies are included for the types of processes used 

for emission sources (e.g., spray booths) in the source 

categories under consideration in this proposal. 

We also consulted information from the Natural Gas 
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STAR program. The Natural Gas STAR program is a flexible, 

voluntary partnership that encourages oil and natural gas 

companies to adopt cost effective technologies and 

practices that improve operational efficiency and reduce 

pollutant emissions. The program provides the oil and gas 

industry with information on new techniques and 

developments to reduce pollutant emissions from the various 

processes.

2. What are the results and proposed decisions from the 

technology review?

There are three types of emission sources covered by 

the two oil and gas NESHAP. These sources and the control 

technologies (including add-on control devices and process 

modifications) considered during the development of the 

MACT standards are: Glycol dehydrators (combustion devices, 

recovery devices, process modifications), storage vessels 

with the PFE (combustion devices, recovery devices) and 

equipment leaks (LDAR programs, specific equipment 

modifications). Dehydrators are addressed by both 40 CFR 

part 63, subpart HH and 40 CFR part 63, subpart HHH, while 

equipment leaks and storage vessels with the PFE are only 

covered by subpart HH.

Since the promulgation of 40 CFR part 63, subpart HH, 
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which established MACT standards to address HAP emissions 

from equipment leaks at gas processing plants, the EPA has 

developed LDAR programs that are more stringent than what 

is required in subpart HH. The most prevalent differences 

between these more stringent programs and subpart HH relate 

to the frequency of monitoring and the concentration which 

constitutes a “leak.” We do consider these programs to 

represent a development in practices and evaluated whether 

to revise the MACT standards for equipment leaks at natural 

gas processing plants under subpart HH in light of this 

development.

An analysis was performed above in section VI.B.1 to 

assess the VOC reduction, costs and other impacts 

associated with these more stringent LDAR program options 

at natural gas processing plants. One option considered was 

to require compliance with 40 CFR part 60, subpart VVa 

instead of 40 CFR part 60, subpart VV (the current NSPS 

requirement for equipment leaks of VOC at natural gas 

processing plants), which changes the leak definition 

(based on methane) from 10,000 ppm to 500 ppm and requires 

monitoring of connectors. Because the current leak 

definition under NESHAP 40 CFR part 63, subpart HH is the 

same as that in NSPS subpart VV, and the ratio of VOC to 
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HAP is approximately 20 to 1, we expect that the HAP 

reduction would be 1/20th of the VOC reduction under 

subpart VVa. The estimated incremental cost for that option 

was determined to be $3,340 per ton of VOC. Based on the 

20-to-1 ratio, we estimate the incremental cost to control 

HAP at the subpart VVa level would be approximately $66,800 

per ton of HAP ($73,480/Mg). Other options considered in 

section VI.B.1 of this preamble (and the incremental cost 

of each option for reducing HAP) are as follows: The use of 

an optical gas imaging camera monthly with an annual EPA 

Method 21 check ($129,000 per ton of HAP/$143,600 per Mg, 

if purchasing the camera; $93,000 per ton of HAP/$103,300 

per Mg, if renting the camera); monthly optical gas 

imagining alone; and annual optical gas imaging.38 In light 

of the above, we do not believe that the additional costs 

of these programs are justified.

In addition to the plant-wide evaluations, a component 

analysis was also evaluated at gas processing plants for 

the 40 CFR part 60, subpart VVa-level of control (option 1 

 

38 As stated above in section VI.B.1, emissions for the two 

options using the optical gas imaging camera alone cannot be 

quantified and, therefore, no cost effectiveness values were 

determined.
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considered in section VI.B.1).39 That assessment shows that 

the subpart VVa-level of control for connectors has an 

incremental cost effectiveness of $4,360 per ton for VOC 

for connectors and $144 per ton for VOC for valves. This 

means the incremental cost to control HAP would be 

approximately $87,200 per ton ($96,900/Mg) for connectors 

and $2,880 per ton ($3,200/Mg) for valves. We do not 

believe the additional cost for the more stringent 

requirement for connectors is justified, but the additional 

cost for valves is justified. Therefore, we are proposing 

to revise the equipment leak requirements in 40 CFR part 

63, subpart HH to lower the leak definition for valves to 

an instrument reading of at least 500 ppm as a result of 

our technology review. 

Some of the practices, processes or control 

technologies listed by the Natural Gas STAR program 

applicable to the emission sources in these categories were 

not identified and evaluated during the original MACT 

development. While the Natural Gas STAR program does 

contain information regarding new innovative techniques 

that are available to reduce HAP emissions, they are not 

 

39 Because optical gas imaging is used to view several pieces of 

equipment at a facility at once to survey for leaks, options 

involving imaging are not amenable to a component by component 

analysis.
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considered to have emission reductions higher than what is 

set by the original MACT. One control technology identified 

in the Natural Gas STAR program that would result in no HAP 

emissions from glycol dehydration units would be the 

replacement of a glycol dehydration unit with a desiccant 

dehydrator. This technology cannot be used for natural gas 

operations with gas streams having high temperature, high 

volume, and low pressure. Due to the limitations posed by 

these conditions, we do not consider desiccant dehydrators 

as MACT.

For storage vessels, the applicable technologies 

identified by the Gas STAR program, which are evaluated 

above for proposal under NSPS in section VI.B.4, are 

similar to the cover and control technologies currently 

required for storage vessels under the existing MACT. 

Therefore, these technologies would not result in any 

further emissions reductions than what is achieved by the 

original MACT.

Our review of the RBLC did not identify any practices, 

processes and control technologies applicable to the 

emission sources in these categories that were not 

identified and evaluated during the original MACT 

development. In light of the above, we are not proposing 
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any revisions to the existing MACT standards for storage 

vessels pursuant to section 112(d)(6) of the CAA.

E. What other actions are we proposing?

1. Combustion Control Device Testing

As explained below in section VII.E.2, under our 

proposal, performance testing would be required initially 

and every 5 years for non-condenser control devices. 

However, for certain enclosed combustion control devices, 

we are proposing to allow, as an alternative to on-site 

testing, a performance test conducted by a control device 

manufacturer in accordance with the procedures provided in 

this proposal. We propose to allow a unit whose model meets 

the proposed performance criteria to claim a BTEX or HAP 

destruction efficiency of 98 percent at the facility. This 

value is lower than the 99.9-percent destruction efficiency 

required in the manufacturers’ test due to variations 

between the test fuel specified and the gas streams 

combusted at the actual facility. A source subject to the 

small dehydrator BTEX limit would use the 98-percent 

destruction efficiency to calculate their dehydrator’s BTEX 

emissions for the purpose of demonstrating compliance. For 

the 95-percent control MACT standard, a control device 

matching the tested model would be considered to meet that 
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requirement. Once a device has been demonstrated to meet 

the proposed performance criteria (and, therefore, is 

assigned a 98-percent destruction efficiency), installation 

of a unit matching the tested model at a facility would 

require no further performance testing (i.e., periodic 

tests would not be required every 5 years).

We are proposing this alternative to minimize issues

associated with performance testing of certain combustion 

control devices. We believe that testing units that are not 

configured with a distinct combustion chamber present 

several technical issues that are more optimally addressed 

through manufacturer testing, and once these units are 

installed at a facility, through periodic inspection and 

maintenance in accordance with manufacturers’ 

recommendations. One issue is that an extension above 

certain existing combustion control device enclosures will 

be necessary to get adequate clearance above the flame 

zone. Such extensions can more easily be configured by the 

manufacturer of the control device rather than having to 

modify an extension in the field to fit devices at every 

site. Issues related to transporting, installing and 

supporting the extension in the field are also eliminated 

through manufacturer testing. Another concern is that the 
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pitot tube used to measure flow can be altered by radiant 

heat from the flame such that gas flow rates are not 

accurate. This issue is best overcome by having the 

manufacturer select and use the pitot tube best suited to 

their specific unit. For these reasons, we believe the 

manufacturers’ test is appropriate for these control 

devices with ongoing performance ensured by periodic 

inspection and maintenance.

This proposed alternative does not apply to flares, as 

defined in 40 CFR 63.761 and 40 CFR 63.1271, which must 

demonstrate compliance by meeting the design and operation 

requirements in 40 CFR 63.11(b), 40 CFR 63.772(e)(2) and 40 

CFR 63.1282(d)(2). It also would not apply to thermal 

oxidizers having a combustion chamber/firebox where 

combustion temperature and residence time can be measured 

during an on-site performance test and are valid indicators 

of performance. These thermal oxidizers do not present the 

issues described above relative to on-site performance 

testing and, therefore, do not need an alternative testing 

option. The proposed alternative would, therefore, apply to 

enclosed combustion control devices except for these 

thermal oxidizers.

In conjunction with the proposed manufacturer testing 
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alternative, we are proposing to add a definition for flare 

to clarify that flares, as referenced in the NESHAP (and to 

which the proposed testing alternative does not apply),

refers to a thermal oxidation system with an open flame 

(i.e., without enclosure). Accordingly, any thermal 

oxidation system that does not meet the proposed flare 

definition would be considered an enclosed combustion 

control device.

We estimate that there are many existing facilities 

currently using enclosed combustion control devices that 

would be required to either conduct an on-site performance 

test or install and operate a control device tested by the 

manufacturer under our proposal. Given the estimated number 

of these combustion control devices in use, the time 

required for manufacturers to test and manufacture such 

units, we are proposing that existing sources have up to 3 

years from the date of the final rules’ publication date to 

comply with the initial performance testing requirements.

2. Monitoring, Recordkeeping and Reporting

We are proposing to make changes to the monitoring 

requirements described below to address issues we have 

identified through a monitoring sufficiency review 

performed during the RTR process. First, we are including 
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calibration procedures associated with parametric 

monitoring requirements in the existing NESHAP. The NESHAP 

require parametric monitoring of control device parameters 

(e.g., temperatures or flowrate monitoring), but did not 

include information on calibration or included inadequate 

information on calibration of monitoring devices. 

Therefore, we are specifying the calibration requirements 

for temperature and flow monitors that the NESHAP currently 

lacks.

In addition, under the current NESHAP, a design 

analysis can be used in lieu of performance testing to 

demonstrate compliance and establish operating parameter 

limits. We are proposing to allow the use of the design 

evaluation alternative only when the control device being 

used is a condenser. The design evaluation option is 

appropriate for condensers because their emissions can be

accurately predicted using readily available physical 

property information (e.g., vapor pressure data and 

condensation calculations). In those cases, one would not 

need to conduct emissions testing to determine actual 

emissions to demonstrate compliance with the MACT standard. 

For example, a requirement that "the temperature at the 

outlet of the condenser shall be maintained at 50o
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Fahrenheit below the condensation temperature calculated 

for the compound of interest using the reference equation” 

(e.g., National Institute of Standards and Technology 

Chemistry WebBook at http://webbook.nist.gov/chemistry/) is 

adequate to assure proper operation of the condenser and,

therefore, compliance with the required emission standard.

For other types of control technologies, such as 

carbon adsorption systems and enclosed combustion devices,40

the ability to predict emissions depends on data developed 

by the vendor and such data may not reliably result in an 

accurate prediction of emissions from a specific facility. 

There are variables (e.g., air to fuel ratios and waste 

constituents for combustion; varying organic 

concentrations, constituents and capacity issues, including 

break-through for carbon adsorption) that make theoretical 

predictions less reliable. The effects of these sitespecific variables on emissions are not easily predictable 

and establishing monitoring conditions (e.g., combustion 

temperature, vacuum regeneration) based on vendor data will 

likely not account for those variables. Therefore, we 

propose to eliminate the design evaluation alternative for 

 

40 The design analysis alternative in the existing MACT does not 

apply to flares. As previously mentioned, the existing MACT 

provides separate design and operation requirements for flares.
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non-condenser controls.

For non-condenser controls (and condensers not using 

the design analysis option), in addition to the initial 

compliance testing, we are proposing that performance tests 

be conducted at least once every 5 years and whenever 

sources desire to establish new operating limits. Under the 

current NESHAP, a performance test is only conducted in two 

instances: (1) As an alternative to a design analysis for 

their compliance demonstration and identification of 

operating parameter ranges and (2) as a requirement to 

resolve a disagreement between the EPA and the owner or 

operator regarding the design analysis. The current NESHAP 

do not require additional performance testing beyond these 

two cases (i.e., there is no periodic testing requirement). 

As mentioned above, we are proposing to remove the design 

evaluation option for non-condenser controls. For noncondenser controls (and condensers not using the design 

analysis option), the proposed periodic testing would 

ensure compliance with the emission standards by verifying 

that the control device is meeting the necessary HAP 

destruction efficiency determined in the initial 

performance test. As discussed above in section VII.E.1, we 

are proposing that combustion control devices tested under 
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the manufacturers’ procedure are not required to conduct 

periodic testing. In addition, we are also proposing that 

combustion control devices that can demonstrate a uniform 

combustion zone temperature meeting the required control 

efficiency during the initial performance test are exempt 

from periodic testing. The requirement for continuous 

monitoring of combustion zone temperature is an accurate 

indicator of control device performance and eliminates the 

need for future testing. 

The current NESHAP (40 CFR 63.771(d) and 40 CFR 

63.1281(d)) require operating an enclosed combustion device 

at a minimum residence time of 0.5 seconds at a minimum 

temperature of 760 degrees Celsius. We are proposing to 

remove the residence time requirement. The residence time

requirement is not needed because the compliance 

demonstration made during the performance test is 

sufficient to ensure that the combustion device has 

adequate residence time to ensure the needed destruction 

efficiency. Therefore, we are proposing to remove the 

residence time requirement.

We are also clarifying at 40 CFR 63.773(d)(3)(i) and 

40 CFR 63.1283(d)(3)(i) for thermal vapor incinerators, 

boilers and process heaters, that the temperature sensor 
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shall be installed at a location representative of the

combustion zone temperature. Currently, the regulation 

requires that the temperature sensor be installed at a 

location “downstream of the combustion zone” because we had 

thought that the temperature downstream would be 

representative of combustion zone temperature. We have now 

learned that may or may not be the case. We are, therefore,

proposing to amend this provision to more accurately 

reflect the intended requirement.

Next, consistent with revisions for SSM, we’ve revised 

40 CFR 63.771(d)(4)(i) and 40 CFR 63.1281(d)(4)(i), except 

when maintenance or repair on a unit cannot be completed 

without a shutdown of the control device. 

Also, we’ve updated the criteria for prior performance 

test results that can be used to demonstrate compliance in 

lieu of conducting a performance test. These updates ensure 

that data for determining compliance are accurate, up-todate, and truly representative of actual operating 

conditions. 

In addition, we are proposing to revise the 

temperature monitoring device minimum accuracy criteria in 

40 CFR 63.773(d)(3)(i) to better reflect the level of 

performance that is required of the temperature monitoring 
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devices. We believe that temperature monitoring devices 

currently used to meet the requirements of the NESHAP can 

meet the proposed revised criteria without modification. 

Also, we are proposing to revise the calibration gas 

concentration for the no detectable emissions procedure 

applicable to closed vent systems in 40 CFR 

63.772(c)(4)(ii) from 10,000 ppmv to 500 ppmv methane to be 

consistent with the leak threshold of 500 ppmv in 40 CFR 

part 63, subpart HH. The current calibration level is 

inconsistent with achieving accurate readings at the level 

necessary to demonstrate there are no detectable emissions. 

Also, we are proposing recordkeeping and reporting 

requirements for carbon adsorption systems. The current 

NESHAP require the replacement of all carbon in the carbon 

adsorption system with fresh carbon on a regular, 

predetermined time interval that is no longer than the 

carbon service life established for the carbon system, but 

provide no recordkeeping or reporting requirement to 

document and assure compliance with this standard. We 

believe that maintaining some sort of log book is a 

reasonable alternative combined with a requirement to 

report instances when specified practices are not followed. 

Therefore, the proposed rule adds reporting and 
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recordkeeping requirements for establishing a schedule and 

maintaining logs of carbon replacement. 

Finally, as noted above in section VII.B.1, we are 

proposing a BTEX emissions limit for small glycol 

dehydration unit process vents. For the compliance 

demonstration, we propose that parametric monitoring of the 

control device be performed. We believe that parametric 

monitoring is adequate for glycol dehydrators in these two 

source categories because temperature monitoring, whether 

it be to verify proper condenser or combustion device 

operation, is a reliable indicator of performance for 

reducing organic HAP emissions. We also considered the use 

of a continuous emissions monitoring system (CEMS) to 

monitor compliance. However, for glycol dehydrators in the 

oil and natural gas sector, the necessary electricity, 

weather-protective enclosures and daily staffing are not 

usually available. We, therefore, question the technical 

feasibility of operating a CEMS correctly in this sector. 

We request comment on the practicality of including 

provisions in the final rule for a CEMS to monitor BTEX 

emissions for small glycol dehydration units.

3. Startup, Shutdown, Malfunction

The United States Court of Appeals for the District of 
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Columbia Circuit vacated portions of two provisions in the 

EPA’s CAA section 112 regulations governing the emissions 

of HAP during periods of SSM. Sierra Club v. EPA, 551 F.3d 

1019 (D.C. Cir. 2008), cert. denied, 130 S. Ct. 1735 (U.S. 

2010). Specifically, the Court vacated the SSM exemption 

contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), that 

is part of a regulation, commonly referred to as the 

General Provisions Rule, that the EPA promulgated under 

section 112 of the CAA. When incorporated into CAA section 

112(d) regulations for specific source categories, these 

two provisions exempt sources from the requirement to 

comply with the otherwise applicable CAA section 112(d) 

emission standard during periods of SSM.

We are proposing the elimination of the SSM exemption 

in the two oil and gas NESHAP. Consistent with Sierra Club

v. EPA, the EPA is proposing to apply the standards in 

these NESHAP at all times. In addition, we are proposing to

revise 40 CFR 63.771(d)(4)(i) and 40 CFR 63.1281(d)(4)(i)

to remove the provision allowing shutdown of the control 

device during maintenance or repair. We are also proposing 

several revisions to the General Provisions applicability

table for the MACT standard. For example, we are proposing 

to eliminate the incorporation of the General Provisions’ 
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requirement that the source develop a SSM plan. We are also 

proposing to eliminate or revise certain recordkeeping and 

reporting requirements related to the SSM exemption. The 

EPA has attempted to ensure that we have not included in 

the proposed regulatory language any provisions that are 

inappropriate, unnecessary or redundant in the absence of 

the SSM exemption. We are specifically seeking comment on 

whether there are any such provisions that we have 

inadvertently incorporated or overlooked.

In proposing the MACT standards in these rules, the 

EPA has taken into account startup and shutdown periods. We 

believe that operations and emissions do not differ from 

normal operations during these periods such that it 

warrants a separate standard. Therefore, we have not 

proposed different standards for these periods. 

Periods of startup, normal operations and shutdown are 

all predictable and routine aspects of a source’s 

operations. However, by contrast, malfunction is defined as 

a “sudden, infrequent and not reasonably preventable 

failure of air pollution control and monitoring equipment, 

process equipment or a process to operate in a normal or 

usual manner * * * ” (40 CFR 63.2). The EPA has determined 

that malfunctions should not be viewed as a distinct 
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operating mode and, therefore, any emissions that occur at 

such times do not need to be factored into development of 

CAA section 112(d) standards, which, once promulgated, 

apply at all times. In Mossville Environmental Action Now

v. EPA, 370 F.3d 1232, 1242 (D.C. Cir. 2004), the Court 

upheld as reasonable, standards that had factored in 

variability of emissions under all operating conditions. 

However, nothing in CAA section 112(d) or in case law 

requires that the EPA anticipate and account for the 

innumerable types of potential malfunction events in 

setting emission standards. See Weyerhaeuser v. Costle, 590 

F.2d 1011, 1058 (D.C. Cir. 1978), (“In the nature of 

things, no general limit, individual permit, or even any 

upset provision can anticipate all upset situations. After 

a certain point, the transgression of regulatory limits 

caused by "uncontrollable acts of third parties," such as 

strikes, sabotage, operator intoxication or insanity, and a 

variety of other eventualities, must be a matter for the 

administrative exercise of case-by-case enforcement 

discretion, not for specification in advance by 

regulation.”). 

Further, it is reasonable to interpret CAA section 

112(d) as not requiring the EPA to account for malfunctions 
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in setting emissions standards. For example, we note that 

CAA section 112 uses the concept of “best performing” 

sources in defining MACT, the level of stringency that 

major source standards must meet. Applying the concept of 

“best performing” to a source that is malfunctioning 

presents significant difficulties. The goal of best 

performing sources is to operate in such a way as to avoid 

malfunctions of their units. 

Moreover, even if malfunctions were considered a 

distinct operating mode, we believe it would be 

impracticable to take malfunctions into account in setting 

CAA section 112(d) standards for oil and natural gas 

production facility and natural gas transmission and 

storage operations. As noted above, by definition, 

malfunctions are sudden and unexpected events, and it would 

be difficult to set a standard that takes into account the 

myriad different types of malfunctions that can occur 

across all sources in each source category. Moreover, 

malfunctions can also vary in frequency, degree and 

duration, further complicating standard setting. 

In the event that a source fails to comply with the 

applicable CAA section 112(d) standards as a result of a 

malfunction event, the EPA would determine an appropriate 
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response based on, among other things, the good faith 

efforts of the source to minimize emissions during 

malfunction periods, including preventative and corrective 

actions, as well as root cause analyses to ascertain and 

rectify excess emissions. The EPA would also consider 

whether the source's failure to comply with the CAA section 

112(d) standard was, in fact, “sudden, infrequent, not 

reasonably preventable” and was not instead “caused in part 

by poor maintenance or careless operation.” 40 CFR 63.2 

(definition of malfunction).

Finally, the EPA recognizes that even equipment that 

is properly designed and maintained can sometimes fail and 

that such failure can sometimes cause or contribute to an 

exceedance of the relevant emission standard. (See, e.g., 

State Implementation Plans: Policy Regarding Excessive 

Emissions During Malfunctions, Startup, and Shutdown

(September 20, 1999); Policy on Excess Emissions During 

Startup, Shutdown, Maintenance, and Malfunctions (February 

15, 1983)). The EPA is, therefore, proposing to add to the 

final rule an affirmative defense to civil penalties for 

exceedances of emission limits that are caused by 

malfunctions in both of the MACT standards addressed in 

this proposal. See 40 CFR 63.761 for sources subject to the 
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oil and natural gas production MACT standards, or 40 CFR 

63.1271 for sources subject to the natural gas transmission 

and storage MACT standards (defining “affirmative defense” 

to mean, in the context of an enforcement proceeding, a 

response or defense put forward by a defendant, regarding 

which the defendant has the burden of proof and the merits 

of which are independently and objectively evaluated in a 

judicial or administrative proceeding). We also are 

proposing other regulatory provisions to specify the 

elements that are necessary to establish this affirmative 

defense; a source subject to the oil and natural gas 

production facilities or natural gas transmission MACT 

standards must prove by a preponderance of the evidence 

that it has met all of the elements set forth in 40 CFR 

63.762 and a source subject to the natural gas transmission 

and storage facilities MACT standards must prove by a 

preponderance of the evidence that it has met all of the 

elements set forth in 40 CFR 63.1272. (See 40 CFR 22.24.) 

The criteria ensure that the affirmative defense is 

available only where the event that causes an exceedance of 

the emission limit meets the narrow definition of 

malfunction in 40 CFR 63.2 (sudden, infrequent, not 

reasonably preventable and not caused by poor maintenance 
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and or careless operation). For example, to successfully 

assert the affirmative defense, the source must prove by a 

preponderance of evidence that excess emissions “[w]ere 

caused by a sudden, infrequent, and unavoidable failure of 

air pollution control and monitoring equipment, process 

equipment, or a process to operate in a normal or usual 

manner ....” The criteria also are designed to ensure that 

steps are taken to correct the malfunction, to minimize 

emissions in accordance with 40 CFR 63.762 for sources 

subject to the oil and natural gas production facilities 

MACT standards or 40 CFR 63.1272 for sources subject to the 

natural gas transmission and storage facilities MACT 

standards and to prevent future malfunctions. For example,

the source must prove by a preponderance of evidence that 

“[r]epairs were made as expeditiously as possible when the 

applicable emission limitations were being exceeded...” and 

that “[a]ll possible steps were taken to minimize the 

impact of the excess emissions on ambient air quality, the 

environment and human health....” In any judicial or 

administrative proceeding, the Administrator may challenge 

the assertion of the affirmative defense and, if the 

respondent has not met its burden of proving all of the 

requirements in the affirmative defense, appropriate 
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penalties may be assessed in accordance with section 113 of 

the CAA (see also 40 CFR 22.77).

4. Applicability and Compliance

a. Calculating Potential to Emit (PTE)

We are proposing to amend section 40 CFR 

63.760(a)(1)(iii) to clarify that sources must use a glycol 

circulation rate consistent with the definition of PTE in 

40 CFR 63.2 in calculating emissions for purposes of 

determining PTE. Affected parties have misinterpreted the 

current language concerning measured values or annual 

average to apply to a broader range of parameters than was 

intended. Those qualifiers were meant to apply to gas 

characteristics that are measured, such as inlet gas 

composition, pressure and temperature rather than process 

equipment settings. That means that the circulation rate 

used in PTE determinations shall be the maximum under its 

physical and operational design.

In addition to the proposed changes described above, 

we are seeking comment on several PTE related issues. 

According to the data available to the Administrator, when 

40 CFR part 63, subpart HH was promulgated, the level of 

HAP emissions was predominantly driven by natural gas 

throughput (i.e., HAP emissions went up or down in concert 
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with natural gas throughput). Since promulgation, we have 

learned that there is not always a direct correlation 

between HAP emissions and natural gas throughput. We have 

received information suggesting that, in some cases, HAP 

emissions can increase despite decreasing natural gas 

throughput due to changes in gas composition. We are asking 

for comment regarding the likelihood of this occurrence and 

data demonstrating the circumstances where it occurs. In 

light of the potential issue, we are asking for comment 

regarding the addition of provisions in the NESHAP to 

require area sources to recalculate their PTE to confirm 

that they are indeed area sources and whether that 

calculation should be performed on an annual or biannual 

basis to verify that changes in gas composition have not 

increased their emissions. 

b. Definition of Facility and Applicability Criteria

Subpart HH of 40 CFR part 63 (section 63.760(a)(2)) 

currently defines facilities as those where hydrocarbon 

liquids are processed, upgraded or stored prior to the 

point of custody transfer or where natural gas is 

processed, upgraded or stored prior to entering the Natural 

Gas Transmission and Storage source category. We are 

proposing to remove the references to “point of custody 
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transfer” and “transmission and storage source categories”

from the definition because the operations performed at a 

site sufficiently define a facility and the scope of the 

subpart is specified already under 40 CFR 63.760. In 

addition, we are removing the custody transfer reference 

from the applicability criteria in 40 CFR 63.760(a)(2).

Since hydrocarbon liquids can pass through several custody 

transfer points between the well and the final destination, 

the custody transfer criteria is not clear enough. We are,

therefore, proposing to replace the reference to “point of 

custody transfer” with a more specific description of the 

point up to which the subpart applies (i.e., the point 

where hydrocarbon liquids enter either the organic liquids 

distribution or petroleum refineries source categories) and 

exclude custody transfer from that criteria. We believe 

this change eliminates ambiguity and is consistent with the 

oil and natural gas production-specific provisions in the 

organic liquids distribution MACT.

5. Other Proposed Changes to Clarify These Rules

The following lists additional changes to the NESHAP 

we are proposing. This list includes proposed rule changes 

that address editorial corrections and plain language 

revisions:
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 Revise 40 CFR 63.769(b) to clarify that the equipment 

leak provisions in 40 CFR part 63, subpart HH do not 

apply to a source if that source is required to 

control equipment leaks under either 40 CFR part 63, 

subpart H or 40 CFR part 60, subpart KKK. The current 

40 CFR 63.769(b), which states that subpart HH does 

not apply if a source meets the requirements in either 

of the subparts mentioned above, does not clearly 

express our intent that such source must be 

implementing the LDAR provisions in the other 40 CFR 

part 60 or 40 CFR part 63 subparts to qualify for the 

exemption.

 Revise 40 CFR 63.760(a)(1) to clarify that an existing 

area source that increases its emissions to major 

source levels has up to the first substantive 

compliance date to either reduce its emissions below 

major source levels by obtaining a practically 

enforceable permit or comply with the applicable major 

source provisions of 40 CFR part 63, subpart HH. We 

have revised the second to last sentence in 40 CFR 

63.760(a)(1) by removing the parenthetical statement 

because it simply reiterates the last sentence of this 

section and is, therefore, unnecessary.
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 Revise 40 CFR 63.771(d)(1)(ii) and 40 CFR 

63.1281(d)(1)(ii) to clarify that the vapor recovery 

device and “other control device” described in those 

provisions refer to non-destructive control devices 

only.

 Revise the last sentence of 40 CFR 63.764(i) and 40 

CFR 63.1274(g) to clarify the requirements following 

an unsuccessful attempt to repair a leak.

 Updated the email and physical address for area source 

reporting in 40 CFR 63.775(c)(1).

VIII. What are the cost, environmental, energy and economic

impacts of the proposed 40 CFR part 60, subpart OOOO and 

amendments to subparts HH and HHH of 40 CFR part 63?

We are presenting a combined discussion of the 

estimates of the impacts for the proposed 40 CFR part 60,

subpart OOOO and proposed amendments to 40 CFR part 63, 

subpart HH and 40 CFR part 63, subpart HHH. The cost, 

environmental and economic impacts presented in this 

section are expressed as incremental differences between 

the impacts of an oil and natural gas facility complying 

with the amendments to subparts HH and HHH and new 

standards under 40 CFR 60, subpart OOOO and the baseline, 

i.e., the standards before these amendments. The impacts 
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are presented for the year 2015, which will be the year 

that all existing oil and natural gas facilities will have 

to be in compliance, and also the year that will represent 

approximately 5 years of construction of new oil and 

natural gas facilities subject to the NSPS emissions 

limits. The analyses and the documents referenced below can 

be found in Docket ID Numbers EPA-HQ-OAR-2007-0877 and EPAHQ-OAR-2002-0051.

A. What are the affected sources?

We expect that by 2015, the year when all existing 

sources will be required to come into compliance in the 

United States, there will be 97 oil and natural gas 

production facilities and 15 natural gas transmission and 

storage facilities with one or more existing glycol 

dehydration units. We also estimate that there will be an 

additional 329 (there are 47 facilities that already have 

an affected glycol dehydration unit) existing oil and 

natural gas production facilities with existing storage 

vessels that we expect to be affected by these final 

amendments. These facilities operate approximately 134 

glycol dehydration units (115 in production and 19 in 

transmission and storage) and 1,970 storage vessels. 

Approximately 10 oil and natural gas production and two 
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transmission and storage facilities would have new glycol 

dehydration units and 38 production facilities would have 

new dehydration units. We expect new production facilities 

would operate approximately 12 production glycol 

dehydration units and 197 storage vessels and new 

transmission and storage would operate approximately two 

glycol dehydration units.

Based on data provided by the United States Energy 

Information Administration, we anticipate that by 2015 

there will be approximately 21,800 gas wellhead facilities, 

790 reciprocating compressors, 30 centrifugal compressors, 

14,000 pneumatic devices and 300 storage vessels subject to 

the new NSPS for VOC. Some of these affected facilities 

will be built at existing facilities and some at new 

greenfield facilities. Based on data limitations, we assume 

impacts are equal regardless of location.

There are about 21 glycol dehydration units with high 

enough HAP emissions that we believe cannot meet the 

emissions limit without using more than one control 

technique. In developing the cost impacts, we assume that 

they would require multiple controls. The controls for 

which we have detailed cost data are condensers and VRU, so 

we developed costs for both controls to develop what we 
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consider to be a reasonable cost estimate for these 

facilities. This does not imply that we believe these 

facilities will specifically use a combination of a 

condenser and vapor recovery limit, but we do believe the 

combination of these control results is a reasonable 

estimate of cost.

B. How are the impacts for this proposal evaluated?

For these proposed Oil and Natural Gas Production and 

Natural Gas Transmission and Storage NESHAP amendments and 

NSPS, the EPA used two models to evaluate the impacts of 

the regulation on the industry and the economy. Typically,

in a regulatory analysis, the EPA determines the regulatory 

options suitable to meet statutory obligations under the 

CAA. Based on the stringency of those options, the EPA then 

determines the control technologies and monitoring 

requirements that sources might rationally select to comply 

with the regulation. This analysis is documented in an 

engineering analysis. The selected control technologies and 

monitoring requirements are then evaluated in a cost model 

to determine the total annualized control costs. The 

annualized control costs serve as inputs to an Economic 

Impact Analysis model that evaluates the impacts of those 

costs on the industry and society as a whole.
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The Economic Impact Analysis used the National Energy 

Modeling System (NEMS) to estimate the impacts of the 

proposed NSPS on the United States energy system. The NEMS 

is a publically-available model of the United States energy 

economy developed and maintained by the Energy Information 

Administration of the United States DOE and is used to 

produce the Annual Energy Outlook, a reference publication 

that provides detailed forecasts of the energy economy from 

the current year to 2035. The impacts we estimated included 

changes in drilling activity, price and quantity changes in 

the production and consumption of crude oil and natural gas

and changes in international trade of crude oil and natural 

gas. We evaluated whether and to what extent the increased 

production costs imposed by the NSPS might alter the mix of 

fuels consumed at a national level. Additionally, we

combined estimated emissions co-reductions of methane from 

the engineering analysis with NEMS analysis to estimate the 

net change in CO2e GHG from energy-related sources.

C. What are the air quality impacts?

For the oil and natural gas sector NESHAP and NSPS, we 

estimated the emission reductions that will occur due to 

the implementation of the final emission limits. The EPA 

estimated emission reductions based on the control 
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technologies selected by the engineering analysis. These 

emission reductions associated with the proposed amendments 

to 40 CFR part 63, subpart HH and 40 CFR part 63, subpart 

HHH are based on the estimated population in 2008. Under 

the proposed limits for glycol dehydration units and 

storage vessels, we have estimated that the HAP emissions 

reductions will be 1,400 tpy for existing units subject to 

the proposed emissions limits. 

For the NSPS, we estimated the emission reductions 

that will occur due to the implementation of the final 

emission limits. The EPA estimated emission reductions 

based on the control technologies selected by the 

engineering analysis. These emission reductions are based 

on the estimated population in 2015. Under the proposed 

NSPS, we have estimated that the emissions reductions will 

be 540,000 tpy VOC for affected facilities subject to the 

NSPS.

The control strategies likely adopted to meet the 

proposed NESHAP amendments and the proposed NSPS will 

result in concurrent control of HAP, methane and VOC 

emissions. We estimate that direct reductions in HAP, 

methane and VOC for the proposed rules combined total about 

38,000 tpy, 3.4 million tpy and 540,000 tpy, respectively.
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Under the final standards, new monitoring requirements 

are being added. 

D. What are the water quality and solid waste impacts?

We estimated minimal water quality impacts for the 

proposed amendments and proposed NSPS. For the proposed 

amendments to the NESHAP, we anticipate that the water 

impacts associated with the installation of a condenser 

system for the glycol dehydration unit process vent would 

be minimal. This is because the condensed water collected 

with the hydrocarbon condensate can be directed back into 

the system for reprocessing with the hydrocarbon condensate 

or, if separated, combined with produced water for 

disposal, usually by reinjection. 

Similarly, the water impacts associated with 

installation of a vapor control system either on a glycol 

dehydration unit or a storage vessel would be minimal. This 

is because the water vapor collected along with the 

hydrocarbon vapors in the vapor collection and redirect 

system can be directed back into the system for 

reprocessing with the hydrocarbon condensate or, if 

separated, combined with the produced water for disposal 

for reinjection.

There would be no water impacts expected for 
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facilities subject to the proposed NSPS. Further, we do not 

anticipate any adverse solid waste impacts from the 

implementation of the proposed NESHAP amendments and the 

proposed NSPS.

E. What are the secondary impacts?

Indirect or secondary air quality impacts include 

impacts that will result from the increased electricity 

usage associated with the operation of control devices, as 

well as water quality and solid waste impacts (which were 

just discussed) that might occur as a result of these 

proposed actions. We estimate the proposed amendments to 40 

CFR part 63, subpart HH and 40 CFR part 63, subpart HHH 

will increase emissions of criteria pollutants due to the 

potential use of flares for the control of storage vessels. 

We do not estimate an increased energy demand associated 

with the installation of condensers, VRU or flares. The 

increases in criteria pollutant emissions associated with 

the use of flares to control storage vessels subject to 

existing source standards are estimated to be 5,500 tpy of 

CO2, 16 tpy of carbon monoxide (CO), 3 tpy of NOx, less than 

1 tpy of particulate matter (PM) and 6 tpy total 

hydrocarbons. For storage vessels subject to new source 

standards, increases in secondary air pollutants are 
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estimated to be less than 900 tpy of CO2, 3 tpy of CO, 1 

tpy of NOx, 1 tpy of PM and 1 tpy total hydrocarbons.

In addition, we estimate that the secondary impacts 

associated with the pneumatic controller requirements to 

comply with the proposed NSPS would be about 22 tpy of CO2, 

1 tpy of NOx and 3 tpy PM. For gas wellhead affected 

facilities, we estimate that the use of flares would result 

in increases in criteria pollutant emissions of about 

990,000 tons of CO2, 2,800 tpy of CO, 500 tpy of NOx, 5 tpy 

of PM and 1,000 tpy total hydrocarbons.

F. What are the energy impacts?

Energy impacts in this section are those energy 

requirements associated with the operation of emission 

control devices. Potential impacts on the national energy 

economy from the rule are discussed in the economic impacts 

section. There would be little national energy demand 

increase from the operation of any of the control options 

analyzed under the proposed NESHAP amendments and proposed 

NSPS.

The proposed NESHAP amendments and proposed NSPS 

encourage the use of emission controls that recover 

hydrocarbon products, such as methane and condensate that 

can be used on-site as fuel or reprocessed within the 
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production process for sale. We estimated that the proposed 

standards will result in a net cost savings due to the 

recovery of salable natural gas and condensate. Thus, the 

final standards have a positive impact associated with the 

recovery of non-renewable energy resources.

G. What are the cost impacts?

The estimated total capital cost to comply with the 

proposed amendments to 40 CFR part 63, subpart HH for major 

sources in the Oil and Natural Gas Production source 

category is approximately $51.5 million. The total capital 

cost for the proposed amendments to 40 CFR part 63, subpart 

HHH for major sources in the Natural Gas Transmission and 

Storage source category is estimated to be approximately 

$370 thousand. All costs are in 2008 dollars.

The total estimated net annual cost to industry to 

comply with the proposed amendments to 40 CFR part 63, 

subpart HH for major sources in the Oil and Natural Gas 

Production source category is approximately $16 million. 

The total net annual cost for proposed amendments to 40 CFR 

part 63, subpart HHH for major sources in the Natural Gas 

Transmission and Storage source category is estimated to be 

approximately $360,000. These estimated annual costs 

include: (1) The cost of capital, (2) operating and 
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maintenance costs, (3) the cost of monitoring, inspection, 

recordkeeping and reporting (MIRR) and (4) any associated 

product recovery credits. All costs are in 2008 dollars.

The estimated total capital cost to comply with the 

proposed NSPS is approximately $740 million in 2008 

dollars. The total estimated net annual cost to industry to 

comply with the proposed NSPS is approximately $740 million 

in 2008 dollars. This annual cost estimate includes: (1) 

The cost of capital, (2) operating and maintenance costs

and (3) the cost of MIRR. This estimated annual cost does 

not take into account any producer revenues associated with 

the recovery of salable natural gas and hydrocarbon 

condensates. 

When revenues from additional product recovery are 

considered, the proposed NSPS is estimated to result in a 

net annual engineering cost savings overall. When including 

the additional natural gas recovery in the engineering cost 

analysis, we assume that producers are paid $4 per thousand 

cubic feet (Mcf) for the recovered gas at the wellhead. 

The engineering analysis cost analysis assumes the value of 

recovered condensate is $70 per barrel. Based on the 

engineering analysis, about 180,000,000 Mcf (180 billion 

cubic feet) of natural gas and 730,000 barrels of 
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condensate are estimated to be recovered by control 

requirements in 2015. Using the price assumptions, the 

estimated revenues from natural gas product recovery are 

approximately $780 million in 2008 dollars. This savings is 

estimated at $45 million in 2008 dollars.

Using the engineering cost estimates, estimated 

natural gas product recovery, and natural gas product price 

assumptions, the net annual engineering cost savings is 

estimated for the proposed NSPS at about $45 million in 

2008 dollars. Totals may not sum due to independent 

rounding.

As the price assumption is very influential on 

estimated annualized engineering costs, we performed a 

simple sensitivity analysis of the influence of the assumed 

wellhead price paid to natural gas producers on the overall 

engineering annualized costs estimate of the proposed NSPS. 

At $4.22/Mcf, the price forecast reported in the 2011 

Annual Energy Outlook in 2008 dollars, the annualized costs 

are estimated at about -$90 million, which would 

approximately double the estimate of net cost savings of 

the proposed NSPS. As indicated by this difference, EPA has 

chosen a relatively conservative assumption (leading to an 

estimate of few savings and higher net costs) for the 
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engineering costs analysis. The natural gas price at which 

the proposed NSPS breaks-even from an estimated engineering 

costs perspective is around $3.77/Mcf. A $1/Mcf change in

the wellhead natural gas price leads to about a $180 

million change in the annualized engineering costs of the 

proposed NSPS. Consequently, annualized engineering costs 

estimates would increase to about $140 million under a 

$3/Mcf price or decrease to about -$230 million under a 

$5/Mcf price. For further details on this sensitivity 

analysis, please refer the regulatory impact analysis (RIA) 

for this rulemaking located in the docket.

H. What are the economic impacts?

The NEMS analysis of energy system impacts for the 

proposed NSPS option estimates that domestic natural gas 

production is likely to increase slightly (about 20 billion 

cubic feet or 0.1 percent) and average natural gas prices 

to decrease slightly ($0.04 per Mcf in 2008 dollars or 0.9 

percent at the wellhead for onshore producers in the lower 

48 states) for 2015, the year of analysis. This increase in 

production and decrease in wellhead price is largely a 

result of the increased natural gas and condensate recovery 

as a result of complying with the NSPS. Domestic crude oil 

production is not expected to change, while average crude 
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oil prices are estimated to decrease slightly ($0.02/barrel 

in 2008 dollars or less than 0.1 percent at the wellhead 

for onshore producers in the lower 48 states) in the year 

of analysis, 2015. The NEMS-based analysis estimates in the 

year of analysis, 2015, that net imports of natural gas and 

crude will not change significantly. 

Total CO2e emissions from energy-related sources are 

expected to increase about 2.0 million metric tons CO2e or 

0.04 percent under the proposed NSPS, according to the NEMS 

analysis. This increase is attributable largely to natural 

gas consumption increases. This estimate does not include 

CO2e reductions from the implementation of the controls; 

these reductions are discussed in more detail in the 

benefits section that follows.

We did not estimate the energy economy impacts of the 

proposed NESHAP amendments using NEMS, as the expected 

costs of the rule are not likely to have estimable impacts 

on the national energy economy. 

I. What are the benefits?

The proposed Oil and Natural Gas NSPS and NESHAP 

amendments are expected to result in significant reductions 

in existing emissions and prevent new emissions from 

expansions of the industry. These proposed rules combined 
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are anticipated to reduce 38,000 tons of HAP, 540,000 tons 

of VOC and 3.4 million tons of methane. These pollutants 

are associated with substantial health effects, welfare 

effects and climate effects. With the data available, we 

are not able to provide credible health benefit estimates 

for the reduction in exposure to HAP, ozone and PM (2.5 

microns and less) (PM2.5) for these rules, due to the 

differences in the locations of oil and natural gas 

emission points relative to existing information and the 

highly localized nature of air quality responses associated 

with HAP and VOC reductions.

This is not to imply that there are no benefits of the 

rules; rather, it is a reflection of the difficulties in 

modeling the direct and indirect impacts of the reductions 

in emissions for this industrial sector with the data 

currently available. In addition to health improvements, 

there will be improvements in visibility effects, ecosystem 

effects and climate effects, as well as additional product 

recovery.

Although we do not have sufficient information or 

modeling available to provide quantitative estimates for 

this rulemaking, we include a qualitative assessment of the 

health effects associated with exposure to HAP, ozone and 
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PM2.5 in the RIA for this rule. These qualitative effects 

are briefly summarized below, but for more detailed 

information, please refer to the RIA, which is available in 

the docket. One of the HAP of concern from the oil and 

natural gas sector is benzene, which is a known human 

carcinogen, and formaldehyde, which is a probable human 

carcinogen. VOC emissions are precursors to both PM2.5 and 

ozone formation. As documented in previous 

analyses (U.S. EPA, 200641 and U.S. EPA, 201042), exposure to 

PM2.5 and ozone is associated with significant public health 

effects. PM2.5 is associated with health effects such as 

premature mortality for adults and infants, cardiovascular 

morbidity, such as heart attacks, hospital admissions and 

respiratory morbidity such as asthma attacks, acute and 

chronic bronchitis, hospital and emergency room visits, 

work loss days, restricted activity days and respiratory 

 

41 U.S. EPA. RIA. National Ambient Air Quality Standards for 

Particulate Matter, Chapter 5. Office of Air Quality Planning and 

Standards, Research Triangle Park, NC. October 2006. Available on 

the Internet at 

<http://www.epa.gov/ttn/ecas/regdata/RIAs/Chapter%205--

Benefits.pdf>.

42 U.S. EPA. RIA. National Ambient Air Quality Standards for 

Ozone. Office of Air Quality Planning and Standards, Research 

Triangle Park, NC. January 2010. Available on the Internet at 

<http://www.epa.gov/ttn/ecas/regdata/RIAs/s1-

supplemental_analysis_full.pdf>.
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symptoms, as well as visibility impairment.43 Ozone is 

associated with health effects such as respiratory 

morbidity such as asthma attacks, hospital and emergency 

department visits, school loss days and premature 

mortality, as well as injury to vegetation and climate 

effects.44 

In addition to the improvements in air quality and 

resulting benefits to human health and non-climate welfare 

effects previously discussed, this proposed rule is 

expected to result in significant climate co-benefits due 

to anticipated methane reductions. Methane is a potent GHG 

that, once emitted into the atmosphere, absorbs terrestrial 

infrared radiation, which contributes to increased global 

warming and continuing climate change. Methane reacts in 

the atmosphere to form ozone and ozone also impacts global 

temperatures. According to the Intergovernmental Panel on 

Climate Change (IPCC) 4th Assessment Report (2007), methane 

is the second leading long-lived climate forcer after CO2

 

43 U.S. EPA. Integrated Science Assessment for Particulate Matter

(Final Report). EPA-600-R-08-139F. National Center for 

Environmental Assessment—RTP Division. December 2009. Available 

at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.

44 U.S. EPA. Air Quality Criteria for Ozone and Related 

Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. 

Washington, DC: U.S. EPA. February 2006. Available on the 

Internet at 

http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.
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globally. Total methane emissions from the oil and gas 

industry represent about 40 percent of the total 

methane emissions from all sources and account for about 5

percent of all CO2e emissions in the United States, with 

natural gas systems being the single largest contributor to 

United States anthropogenic methane emissions.45 Methane, in 

addition to other GHG emissions, contributes to warming of 

the atmosphere, which, over time, leads to increased air 

and ocean temperatures, changes in precipitation patterns, 

melting and thawing of global glaciers and ice, 

increasingly severe weather events, such as hurricanes of 

greater intensity and sea level rise, among other impacts. 

This rulemaking proposes emission control technologies 

and regulatory alternatives that will significantly 

decrease methane emissions from the oil and natural gas 

sector in the United States. The regulatory alternatives 

proposed for the NESHAP and the NSPS are expected to reduce 

methane emissions annually by about 3.4 million short tons 

or 65 million metric tons CO2e. After considering the 

secondary impacts of this proposal previously discussed, 

such as increased CO2 emissions from well completion 

 

45 U.S. EPA (2011), 2011 U.S. Greenhouse Gas Inventory Report

Executive Summary available on the internet at 

www.epa.gov/climateexchange/emissions/downloads11/US-GHGInventory-2011-Executive Summary.pdf.
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combustion and decreased CO2e emissions because of fuelswitching by consumers, the methane reductions become about 

62 million metric tons CO2e. These reductions represent 

about 26 percent of the baseline methane emissions for this 

sector reported in the EPA’s U.S. Greenhouse Gas Inventory 

Report for 2009 (251.55 million metric tons CO2e when 

petroleum refineries and petroleum transportation are 

excluded because these sources are not examined in this 

proposal). After considering the secondary impacts of this 

proposal, such as increased CO2 emissions from well 

completion combustion and decreased CO2 emissions because 

of fuel-switching by consumers, the CO2e GHG reductions are 

reduced to about 62 million metric tons CO2e. However, it 

is important to note that the emission reductions are based 

upon predicted activities in 2015; the EPA did not forecast 

sector-level emissions in 2015 for this rulemaking. These 

emission reductions equate to the climate benefits of 

taking approximately 11 million typical passenger cars off 

the road or eliminating electricity use from about 7

million typical homes each year.46

The EPA recognizes that the methane reductions proposed 

 

46 U.S. EPA. Greenhouse Gas Equivalency Calculator available at: 

http://www.epa.gov/cleanenergy/energy-resources/calculator.html 

accessed 07/19/11.
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in this rule will provide for significant economic climate 

benefits to society just described. However, there is no 

interagency-accepted methodology to place monetary values 

on these benefits. A ‘global warming potential (GWP)

approach’ of converting methane to CO2e using the GWP of 

methane provides an approximation method for estimating the 

monetized value of the methane reductions anticipated from 

this rule. This calculation uses the GWP of the non-CO2 gas 

to estimate CO2 equivalents and then multiplies these CO2

equivalent emission reductions by the social cost of carbon 

developed by the Interagency Social Cost of Carbon Work

Group to generate monetized estimates of the benefits.

The social cost of carbon is an estimate of the net 

present value of the flow of monetized damages from a 1-

metric ton increase in CO2 emissions in a given year (or 

from the alternative perspective, the benefit to society of 

reducing CO2 emissions by 1 ton). For more information 

about the social cost of carbon, see the Support Document: 

Social Cost of Carbon for Regulatory Impact Analysis Under 

Executive Order 1286647 and RIA for the Light-Duty Vehicle 

 

47 Interagency Working Group on Social Cost of Carbon (IWGSC). 

2010. Technical Support Document: Social Cost of Carbon for 

Regulatory Impact Analysis Under Executive Order 12866. Docket ID 

EPA-HQ-OAR-2009-0472-114577. 
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GHG rule.48 Applying this approach to the methane reductions 

estimated for the proposed NESHAP and NSPS of the oil and 

gas rule, the 2015 climate co-benefits vary by discount 

rate and range from about $370 million to 

approximately $4.7 billion; the mean social cost of carbon

at the 3-percent discount rate results in an estimate of 

about $1.6 billion in 2015. 

The ratio of domestic to global benefits of emission 

reductions varies with key parameter assumptions. For 

example, with a 2.5 or 3 percent discount rate, the U.S. 

benefit is about 7-10 percent of the global benefit, on 

average, across the scenarios analyzed. Alternatively, if 

the fraction of GDP lost due to climate change is assumed 

to be similar across countries, the domestic benefit would 

be proportional to the U.S. share of global GDP, which is 

currently about 23 percent. On the basis of this evidence, 

values from 7 to 23 percent should be used to adjust the 

global SCC to calculate domestic effects. It is recognized 

that these values are approximate, provisional and highly 

speculative. There is no a priori reason why domestic 

 

<http://www.epa.gov/otaq/climate/regulations/scc-tsd.pdf> 

Accessed March 30, 2011.

48 U.S. EPA. Final Rulemaking: Light-Duty Vehicle Greenhouse Gas 

Emissions Standards and Corporate Average Fuel Economy Standards. 

May 2010. Available on the Internet at

http://www.epa.gov/otaq/climate/regulations.htm#finalR.
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benefits should be a constant fraction of net global 

damages over time.49

These co-benefits equate to a range of approximately 

$110 to $1,400 per short ton of methane reduced, depending 

upon the discount rate assumed with a per ton estimate of 

$480 at the 3-percent discount rate. Methane climate cobenefit estimates for additional regulatory alternatives 

are included in the RIA for this proposed rule. These 

social cost of methane benefit estimates are not the same 

as would be derived from direct computations (using the 

integrated assessment models employed to develop the

Interagency Social Cost of Carbon estimates) for a variety 

of reasons, including the shorter atmospheric lifetime of 

methane relative to CO2 (about 12 years compared to CO2

whose concentrations in the atmosphere decay on timescales 

of decades to millennia). The climate impacts also differ 

between the pollutants for reasons other than the radiative 

forcing profiles and atmospheric lifetimes of these gases.

Methane is a precursor to ozone and ozone is a shortlived climate forcer that contributes to global warming. 

The use of the IPCC Second Assessment Report GWP to 

 

49 Interagency Working Group on Social Cost of Carbon (IWGSC). 

2010. Technical Support Document: Social Cost of Carbon for 

Regulatory Impact Analysis Under Executive Order 12866.
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approximate co-benefits may underestimate the direct 

radiative forcing benefits of reduced ozone levels and does

not capture any secondary climate co-benefits involved with 

ozone-ecosystem interactions. In addition, a recent EPA 

National Center of Environmental Economics working 

paper suggests that this quick ‘GWP approach’ to benefits 

estimation will likely understate the climate benefits of 

methane reductions in most cases.50 This conclusion is 

reached using the 100-year GWP for methane of 25 as put 

forth in the IPCC Fourth Assessment Report (AR 4), as 

opposed to the lower value of 21 used in this analysis. 

Using the higher GWP estimate of 25 would increase these 

reported methane climate co-benefit estimates by about 19 

percent. Although the IPCC Assessment Report (AR4)

suggested a GWP of 25 for methane, the EPA has used GWP of 

21 to estimate the methane climate co-benefits for this oil 

and gas proposal in order to provide estimates more 

consistent with global GHG inventories, which currently use 

GWP from the IPCC Second Assessment Report. 

Due to the uncertainties involved with the ‘GWP 

 

50 Marten and Newbold (2011), Estimating the Social Cost of NonCO2 GHG Emissions: Methane and Nitrous Oxide, NCEE Working Paper 

Series #11-01. 

http://yosemite.epa.gov/EE/epa/eed.nsf/WPNumber/2011-

01?OpenDocument.
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approach’ estimates presented and methane climate cobenefits estimates available in the literature, the EPA 

chooses not to compare these co-benefit estimates to the 

costs of the rule for this proposal. Rather, the EPA 

presents the ‘GWP approach’ climate co-benefit estimates as 

an interim method to produce these estimates until the 

Interagency Social Cost of Carbon Work Group develops 

values for non-CO2 GHG. The EPA requests comments from 

interested parties and the public about this interim 

approach specifically and more broadly about appropriate 

methods to monetize the climate benefits of methane 

reductions. In particular, the EPA seeks public comments to 

this proposed rulemaking regarding social cost of methane 

estimates that may be used to value the co-benefits of 

methane emission reductions anticipated for the oil and gas 

industry from this rule. Comments specific to whether GWP 

is an acceptable method for generating a placeholder value 

for the social cost of methane until interagency-modeled 

estimates become available are welcome. Public comments may 

be provided in the official docket for this proposed 

rulemaking in accordance with the process outlined earlier 

in this notice. These comments will be considered in 

developing the final rule for this rulemaking.
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For the proposed NESHAP amendments, a break-even 

analysis suggests that HAP emissions would need to be 

valued at $12,000 per ton for the benefits to exceed the 

costs if the health, ecosystem and climate benefits from 

the reductions in VOC and methane emissions are assumed to 

be zero. Even though emission reductions of VOC and methane 

are co-benefits for the proposed NESHAP amendments, they 

are legitimate components of the total benefit-cost 

comparison. If we assume the health benefits from HAP 

emission reductions are zero, the VOC emissions would need 

to be valued at $1,700 per ton or the methane emissions 

would need to be valued at $3,300 per ton for the cobenefits to exceed the costs. All estimates are in 2008 

dollars. For the proposed NSPS, the revenue from additional 

product recovery exceeds the costs, which renders a breakeven analysis unnecessary when these revenues are included 

in the analysis. Based on the methodology from Fann, 

Fulcher, and Hubbell (2009),

51 ranges of benefit-per-ton

estimates for emissions of VOC indicate that on average in 

the United States, VOC emissions are valued from $1,200 to 

$3,000 per ton as a PM2.5 precursor, but emission reductions 

 

51 Fann, N., C.M. Fulcher, B.J. Hubbell. The influence of 

location, source, and emission type in estimates of the human 

health benefits of reducing a ton of air pollution. Air Qual 

Atmos Health (2009) 2:169-176.
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in specific areas are valued from $280 to $7,000 per ton in 

2008 dollars. As a result, even if VOC emissions from oil 

and natural gas operations result in monetized benefits 

that are substantially below the national average, there is 

a reasonable chance that the benefits of the rule would 

exceed the costs, especially if we were able to monetize 

all of the additional benefits associated with ozone 

formation, visibility, HAP and methane.

IX. Request for Comments

We are soliciting comments on all aspects of this 

proposed action. All comments received during the comment 

period will be considered. In addition to general comments 

on the proposed actions, we are also interested in any 

additional data that may help to reduce the uncertainties 

inherent in the risk assessments. We are specifically 

interested in receiving corrections to the datasets used 

for MACT analyses and risk modeling. Such data should 

include supporting documentation in sufficient detail to 

allow characterization of the quality and 

representativeness of the data or information. Please see 

the following section for more information on submitting 

data. 

X. Submitting Data Corrections
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The facility-specific data used in the source category 

risk analyses, facility-wide analyses and demographic 

analyses for each source category subject to this action 

are available for download on the RTR Web page at 

http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. These data 

files include detailed information for each HAP emissions 

release point at each facility included in the source 

category and all other HAP emissions sources at these 

facilities (facility-wide emissions sources). However, it 

is important to note that the source category risk analysis 

included only those emissions tagged with the MACT code 

associated with the source category subject to the risk 

analysis. 

If you believe the data are not representative or are 

inaccurate, please identify the data in question, provide 

your reason for concern and provide any “improved” data 

that you have, if available. When you submit data, we 

request that you provide documentation of the basis for the 

revised values to support your suggested changes. To submit 

comments on the data downloaded from the RTR Web page, 

complete the following steps:

1. Within this downloaded file, enter suggested 

revisions to the data fields appropriate for that 
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information. The data fields that may be revised include 

the following:

Data Element Definition

Control Measure Are control measures in place? 

(yes or no)

Control Measure Comment

Select control measure from 

list provided and briefly 

describe the control measure

Delete Indicate here if the facility 

or record should be deleted

Delete Comment Describes the reason for 

deletion

Emission Calculation 

Method Code For Revised 

Emissions

Code description of the method 

used to derive emissions. For 

example, CEM, material 

balance, stack test, etc.

Emission Process Group

Enter the general type of 

emission process associated 

with the specified emission 

point

Fugitive Angle

Enter release angle (clockwise 

from true North); orientation 

of the y-dimension relative to 

true North, measured positive 

for clockwise starting at 0 

degrees (maximum 89 degrees)

Fugitive Length

Enter dimension of the source 

in the east-west (x-) 

direction, commonly referred 

to as length (ft)

Fugitive Width

Enter dimension of the source 

in the north-south (y-) 

direction, commonly referred 

to as width (ft)

Malfunction Emissions Enter total annual emissions 

due to malfunctions (TPY)

Malfunction Emissions Max 

Hourly

Enter maximum hourly 

malfunction emissions here 

(lb/hr)

North American Datum

Enter datum for 

latitude/longitude coordinates 

(NAD27 or NAD83); if left 

blank, NAD83 is assumed
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Data Element Definition

Process Comment Enter general comments about 

process sources of emissions

REVISED Address Enter revised physical street 

address for MACT facility here

REVISED City Enter revised city name here

REVISED County Name Enter revised county name here

REVISED Emission Release 

Point Type

Enter revised Emission Release 

Point Type here

REVISED End Date Enter revised End Date here

REVISED Exit Gas Flow Rate

Enter revised Exit Gas 

Flowrate here (ft3/sec)

REVISED Exit Gas 

Temperature 

Enter revised Exit Gas 

Temperature here (OF)

REVISED Exit Gas Velocity Enter revised Exit Gas 

Velocity here (ft/sec)

REVISED Facility Category 

Code

Enter revised Facility 

Category Code here, which 

indicates whether facility is 

a major or area source

REVISED Facility Name Enter revised Facility Name 

here

REVISED Facility Registry 

Identifier

Enter revised Facility 

Registry Identifier here, 

which is an ID assigned by the 

EPA Facility Registry System

REVISED HAP Emissions 

Performance Level Code

Enter revised HAP Emissions 

Performance Level here

REVISED Latitude Enter revised Latitude here 

(decimal degrees)

REVISED Longitude Enter revised Longitude here 

(decimal degrees)

REVISED MACT Code Enter revised MACT Code here

REVISED Pollutant Code Enter revised Pollutant Code 

here

REVISED Routine Emissions Enter revised routine 

emissions value here (TPY)

REVISED SCC Code Enter revised SCC Code here

REVISED Stack Diameter Enter revised Stack Diameter 

here (ft)

REVISED Stack Height Enter revised Stack Height 

here (Ft)

REVISED Start Date Enter revised Start Date here

REVISED State Enter revised state here

REVISED Tribal Code Enter revised Tribal Code here
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Data Element Definition

REVISED Zip Code Enter revised Zip Code here

Shutdown Emissions Enter total annual emissions 

due to shutdown events (TPY)

Shutdown Emissions Max 

Hourly

Enter maximum hourly shutdown 

emissions here (lb/hr)

Stack Comment Enter general comments about 

emission release points

Startup Emissions Enter total annual emissions 

due to startup events (TPY)

Startup Emissions Max 

Hourly

Enter maximum hourly startup 

emissions here (lb/hr)

Year Closed Enter date facility stopped 

operations

2. Fill in the commenter information fields for each 

suggested revision (i.e., commenter name, commenter 

organization, commenter email address, commenter phone 

number and revision comments).

3. Gather documentation for any suggested emissions 

revisions (e.g., performance test reports, material balance 

calculations, etc.).

4. Send the entire downloaded file with suggested 

revisions in Microsoft® Access format and all accompanying 

documentation to Docket ID Number EPA-HQ-OAR-2010-0505

(through one of the methods described in the ADDRESSES

section of this preamble). To expedite review of the 

revisions, it would also be helpful if you submitted a copy 

of your revisions to the EPA directly at RTR@epa.gov in 

addition to submitting them to the docket.
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5. If you are providing comments on a facility with 

multiple source categories, you need only submit one file 

for that facility, which should contain all suggested 

changes for all source categories at that facility. We 

request that all data revision comments be submitted in the 

form of updated Microsoft® Access files, which are provided 

on the http://www.epa.gov/ttn/atw/rrisk/rtrpg.html Web 

page.

XI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

and Executive Order 13563: Improving Regulation and 

Regulatory Review

Under Executive Order 12866 (58 FR 51735, October 4, 

1993), this action is an “economically significant 

regulatory action” because it is likely to have an annual 

effect on the economy of $100 million or more. Accordingly, 

the EPA submitted this action to OMB for review under 

Executive Order 12866 and Executive Order 13563 (76 FR 

3821, January 21, 2011) and any changes made in response to 

OMB recommendations have been documented in the docket for 

this action.

In addition, the EPA prepared a RIA of the potential 

costs and benefits associated with this action. The RIA 
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available in the docket describes in detail the empirical 

basis for the EPA’s assumptions and characterizes the 

various sources of uncertainties affecting the estimates 

below. Table 8 shows the results of the cost and benefits 

analysis for these proposed rules. For more information on 

the benefit and cost analysis, as well as details on the 

regulatory options considered, please refer to the RIA for 

this rulemaking, which is available in the docket.
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Table 8. Summary of the Monetized Benefits, Costs and Net 

Benefits for the Proposed Oil and Natural Gas NSPS and 

NEHSAP Amendments in 2015 (millions of 2008$)1

Proposed NSPS Proposed NESHAP 

Amendments

Proposed NSPS and 

NESHAP Amendments 

Combined

Total 

Monetized 

Benefits2

N/A N/A N/A

Total Costs3 -$45 million $16 million -$29 million

Net Benefits N/A N/A N/A

Non-monetized 

Benefits4,5

37,000 tons of 

HAP

1,400 tons of 

HAP

38,000 tons of 

HAP

540,000 tons of 

VOC 9,200 tons of VOC 540,000 tons of VOC

3.4 million tons 

of methane

4,900 tons of 

methane

3.4 million tons 

of methane

Health effects of HAP exposure

Health effects of PM2.5 and ozone exposure

Visibility impairment

Vegetation effects

Climate effects

1 All estimates are for the implementation year (2015).

2 While we expect that these avoided emissions will result in 

improvements in air quality and reductions in health effects associated 

with HAP, ozone and PM, as well as climate effects associated with 

methane, we have determined that quantification of those benefits 

cannot be accomplished for this rule in a defensible way. This is not 

to imply that there are no benefits of the rules; rather, it is a 

reflection of the difficulties in modeling the direct and indirect 

impacts of the reductions in emissions for this industrial sector with 

the data currently available.

3 The engineering compliance costs are annualized using a 7-percent 

discount rate. The negative cost for the proposed NSPS reflects the 

inclusion of revenues from additional natural gas and hydrocarbon 

condensate recovery that are estimated as a result of the proposed 

NSPS.

4 For the NSPS, reduced exposure to HAP and climate effects are cobenefits. For the NESHAP, reduced VOC emissions, PM2.5 and ozone 

exposure, visibility and vegetation effects and climate effects are cobenefits.

5 The specific control technologies for these proposed rules are 

anticipated to have minor secondary disbenefits. The net CO2-equivalent 

emission reductions are 93,000 metric tons for the NESHAP and 62 

million metric tons for the NSPS.

B. Paperwork Reduction Act
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The information collection requirements in this 

proposed action have been submitted for approval to OMB 

under the Paperwork Reduction Act, 44 U.S.C. 3501, et seq. 

The ICR document prepared by the EPA has been assigned EPA 

ICR Numbers 1716.07 (40 CFR part 60, subpart OOOO), 1788.10 

(40 CFR part 63, subpart HH), 1789.07 (40 CFR part 63, 

subpart HHH) and 1086.10 (40 CFR part 60, subparts KKK and 

subpart LLL).

The information to be collected for the proposed NSPS 

and the proposed NESHAP amendments are based on 

notification, recordkeeping and reporting requirements in 

the NESHAP General Provisions (40 CFR part 63, subpart A), 

which are mandatory for all operators subject to national 

emission standards. These recordkeeping and reporting 

requirements are specifically authorized by section 114 of 

the CAA (42 U.S.C. 7414). All information submitted to the 

EPA pursuant to the recordkeeping and reporting 

requirements for which a claim of confidentiality is made 

is safeguarded according to Agency policies set forth in 40 

CFR part 2, subpart B.

These proposed rules would require maintenance 

inspections of the control devices, but would not require 

any notifications or reports beyond those required by the 
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General Provisions. The recordkeeping requirements require 

only the specific information needed to determine 

compliance.

For sources subject to the proposed NSPS, burden 

changes associated with these amendments result from the 

respondents’ annual reporting and recordkeeping burden 

associated with this proposed rule for this collection 

(averaged over the first 3 years after the effective date 

of the standards). The burden is estimated to be 560,000

labor hours at a cost of $18 million per year. This 

includes the burden previously estimated for sources 

subject to 40 CFR part 60, subpart KKK (which is being 

incorporated into 40 CFR part 60, subpart OOOO). The 

average hours and cost per regulated entity subject to the 

NSPS for oil and natural gas production and natural gas 

transmissions and distribution facilities would be 

110 hours per response and $3,693 per response, based on an 

average of 1,459 operators responding per year and 16 

responses per year.

The estimated recordkeeping and reporting burden after 

the effective date of the proposed amendments is estimated 

for all affected major and area sources subject to the Oil 

and Natural Gas Production NESHAP to be approximately 
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63,000 labor hours per year at a cost of $2.1 million per 

year. For the Natural Gas Transmission and Storage NESHAP, 

the recordkeeping and reporting burden is estimated to be 

2,500 labor hours per year at a cost of $86,800 per year. 

This estimate includes the cost of reporting, including 

reading instructions and information gathering. 

Recordkeeping cost estimates include reading instructions, 

planning activities and conducting compliance monitoring. 

The average hours and cost per regulated entity subject to 

the Oil and Natural Gas Production NESHAP would be 72 hours 

per year and $2,500 per year, based on an average of 

846 facilities per year and three responses per facility. 

For the Natural Gas Transmission and Storage NESHAP, the 

average hours and cost per regulated entity would be 50 

hours per year and $1,600 per year, based on an average of 

53 facilities per year and three responses per facility. 

Burden is defined at 5 CFR 1320.3(b).

An agency may not conduct or sponsor, and a person is 

not required to respond to, a collection of information 

unless it displays a currently valid OMB control number. 

The OMB control numbers for the EPA's regulations in 40 CFR 

are listed in 40 CFR part 9.
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To comment on the Agency's need for this information, 

the accuracy of the provided burden estimates and any 

suggested methods for minimizing respondent burden, the EPA 

has established a public docket for this rule, which 

includes this ICR, under Docket ID Number EPA-HQ-OAR-2010-

0505. Submit any comments related to the ICR to the EPA and 

OMB. See ADDRESSES section at the beginning of this notice 

for where to submit comments to the EPA. Send comments to 

OMB at the Office of Information and Regulatory Affairs, 

Office of Management and Budget, 725 17th Street, NW, 

Washington, DC 20503, Attention: Desk Office for the EPA. 

Since OMB is required to make a decision concerning the ICR 

between 30 and 60 days after [INSERT DATE OF PUBLICATION IN 

THE FEDERAL REGISTER], a comment to OMB is best assured of 

having its full effect if OMB receives it by [INSERT DATE

30 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 

The final rule will respond to any OMB or public comments 

on the information collection requirements contained in 

this proposal.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act generally requires an 

agency to prepare a regulatory flexibility analysis of any 

rule subject to notice and comment rulemaking requirements 
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under the Administrative Procedure Act or any other 

statute, unless the agency certifies that the rule will not 

have a significant economic impact on a substantial number 

of small entities (SISNOSE). Small entities include small 

businesses, small organizations, and small governmental 

jurisdictions. For purposes of assessing the impact of this 

rule on small entities, a small entity is defined as: (1) A

small business whose parent company has no more than 500 

employees (or revenues of less than $7 million for firms 

that transport natural gas via pipeline); (2) a small 

governmental jurisdiction that is a government of a city, 

county, town, school district, or special district with a 

population of less than 50,000; and (3) a small 

organization that is any not-for-profit enterprise which is 

independently owned and operated and is not dominant in its 

field.

Proposed NSPS

After considering the economic impact of the proposed 

NSPS on small entities, I certify that this action will not 

have a SISNOSE. The EPA performed a screening analysis for 

impacts on a sample of expected affected small entities by 

comparing compliance costs to entity revenues. Based upon 

the analysis in the RIA, which is in the Docket, EPA 
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concludes the number of impacted small businesses is 

unlikely to be sufficiently large to declare a SISNOSE. 

Our judgment in this determination is informed by the fact 

that many affected firms are expected to receive revenues 

from the additional natural gas and condensate recovery 

engendered by the implementation of the controls evaluated 

in this RIA. As much of the additional natural gas recovery 

is estimated to arise from completion-related activities, 

we expect the impact on well-related compliance costs to be 

significantly mitigated. This conclusion is enhanced 

because the returns to REC activities occur without a 

significant time lag between implementing the control and 

obtaining the recovered product, unlike many control 

options where the emissions reductions accumulate over long 

periods of time; the reduced emission completions and 

recompletions occur over a short span of time, during which 

the additional product recovery is also accomplished.

Proposed NESHAP Amendments

After considering the economic impact of the proposed 

NESHAP amendments on small entities, I certify that this 

action will not have a SISNOSE. Based upon the analysis in 

the RIA, which is in the Docket, we estimate that 62 of the 

118 firms (53 percent) that own potentially affected 
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facilities are small entities. The EPA performed a

screening analysis for impacts on all expected affected 

small entities by comparing compliance costs to entity 

revenues. Among the small firms, 52 of the 62 (84 percent) 

are likely to have impacts of less than 1 percent in terms 

of the ratio of annualized compliance costs to revenues. 

Meanwhile, 10 firms (16 percent) are likely to have impacts 

greater than 1 percent. Four of these 10 firms are likely 

to have impacts greater than 3 percent. While these 10

firms might receive significant impacts from the proposed 

NESHAP amendments, they represent a very small slice of the 

oil and gas industry in its entirety, less than 0.2 percent 

of the estimated 6,427 small firms in NAICS 211. Although 

this final rule will not impact a substantial number of 

small entities, the EPA, nonetheless, has tried to reduce 

the impact of this rule on small entities by setting the 

final emissions limits at the MACT floor, the least 

stringent level allowed by law. 

We continue to be interested in the potential impacts 

of the proposed rule on small entities and welcome comments 

on issues related to such impacts.

D. Unfunded Mandates Reform Act
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This action contains no Federal mandates under the 

provisions of title II of the Unfunded Mandates Reform Act 

of 1995 (UMRA), 2 U.S.C. 1531-1538 for state, local or 

tribal governments or the private sector. This proposed 

rule does not contain a Federal mandate that may result in 

expenditures of $100 million or more for state, local and 

tribal governments, in the aggregate, or to the private 

sector in any one year. Thus, this proposed rule is not 

subject to the requirements of sections 202 or 205 of UMRA.

This proposed rule is also not subject to the requirements 

of section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect 

small governments. This action contains no requirements 

that apply to such governments nor does it impose 

obligations upon them.
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E. Executive Order 13132: Federalism

This proposed rule does not have federalism 

implications. It will not have substantial direct effects 

on the states, on the relationship between the national 

government and the states, or on the distribution of power 

and responsibilities among the various levels of 

government, as specified in Executive Order 13132. Thus, 

Executive Order 13132 does not apply to this proposed rule. 

In the spirit of Executive Order 13132 and consistent with 

the EPA policy to promote communications between the EPA 

and state and local governments, the EPA specifically 

solicits comment on this proposed rule from state and local 

officials. 

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments

This action does not have tribal implications, as 

specified in Executive Order 13175 (65 FR 67249, November 

9, 2000). It will not have substantial direct effect on 

tribal governments, on the relationship between the Federal 

government and Indian tribes or on the distribution of 

power and responsibilities between the Federal government 

and Indian tribes, as specified in Executive Order 13175. 

Thus, Executive Order 13175 does not apply to this action.
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The EPA specifically solicits additional comment on 

this proposed action from tribal officials.

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

This proposed rule is not subject to Executive Order 

13045 (62 FR 19885, April 23, 1997) because the Agency does 

not believe the environmental health risks or safety risks 

addressed by this action present a disproportionate risk to 

children. This actions’ health and risk assessments are 

contained in section VII.C of this preamble. 

The public is invited to submit comments or identify peerreviewed studies and data that assess effects of early life 

exposure to HAP from oil and natural gas sector activities.

H. Executive Order 13211: Actions Concerning Regulations 

That Significantly Affect Energy Supply, Distribution or 

Use

Executive Order 13211, (66 FR 28,355, May 22, 2001), 

provides that agencies shall prepare and submit to the 

Administrator of the Office of Information and Regulatory 

Affairs, OMB, a Statement of Energy Effects for certain 

actions identified as significant energy actions. Section 

4(b) of Executive Order 13211 defines “significant energy 

actions” as “any action by an agency (normally published in 
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the Federal Register) that promulgates or is expected to 

lead to the promulgation of a final rule or regulation, 

including notices of inquiry, advance notices of proposed 

rulemaking, and notices of proposed rulemaking: (1)(i) That 

is a significant regulatory action under Executive Order 

12866 or any successor order and (ii) is likely to have a 

significant adverse effect on the supply, distribution, or 

use of energy; or (2) that is designated by the 

Administrator of the Office of Information and Regulatory 

Affairs as a significant energy action.” 

The proposed rules will result in the addition of 

control equipment and monitoring systems for existing and 

new sources within the oil and natural gas industry. The 

proposed NESHAP amendments are unlikely to have a 

significant adverse effect on the supply, distribution or 

use of energy. As such, the proposed NESHAP amendments are 

not “significant energy actions” as defined in Executive 

Order 13211 (66 FR 28355, May 22, 2001). 

The proposed NSPS is also unlikely to have a 

significant effect on the supply, distribution or use of 

energy. As such, the proposed NSPS is not a “significant 

energy action” as defined in Executive Order 13211 (66 FR 
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28355, May 22, 2001). The basis for the determination is as 

follows.

As discussed in the impacts section of the Preamble, 

we use the NEMS to estimate the impacts of the proposed 

NSPS on the United States energy system. The NEMS is a 

publically available model of the United States energy 

economy developed and maintained by the Energy Information 

Administration of the United States DOE and is used to 

produce the Annual Energy Outlook, a reference publication 

that provides detailed forecasts of the United States 

energy economy. 

Proposed emission controls for the NSPS capture VOC 

emissions that otherwise would be vented to the atmosphere. 

Since methane is co-emitted with VOC, a large proportion of 

the averted methane emissions can be directed into natural 

gas production streams and sold. One pollution control 

requirement of the proposed NSPS also captures saleable 

condensates. The revenues from additional natural gas and 

condensate recovery are expected to offset the costs of 

implementing the proposed NSPS. 

The analysis of energy impacts for the proposed NSPS 

that includes the additional product recovery shows that 

domestic natural gas production is estimated to increase 
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(20 billion cubic feet or 0.1 percent) and natural gas 

prices to decrease ($0.04/Mcf or 0.9 percent at the 

wellhead for producers in the lower 48 states) in 2015, the 

year of analysis. Domestic crude oil production is not 

estimated to change, while crude oil prices are estimated 

to decrease slightly ($0.02/barrel or less than 0.1 percent 

at the wellhead for producers in the lower 48 states) in 

2015, the year of analysis. All prices are in 2008 dollars.

Additionally, the NSPS establishes several performance 

standards that give regulated entities flexibility in 

determining how to best comply with the regulation. In an 

industry that is geographically and economically 

heterogeneous, this flexibility is an important factor in 

reducing regulatory burden.

For more information on the estimated energy effects, 

please refer to the economic impact analysis for this 

proposed rule. The analysis is available in the RIA, which 

is in the public docket.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act of 1995 (NTTAA), Public Law No. 104-113 (15 

U.S.C. 272 note) directs the EPA to use voluntary consensus 

standards (VCS) in its regulatory activities unless to do 
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so would be inconsistent with applicable law or otherwise 

impractical. VCS are technical standards (e.g., materials 

specifications, test methods, sampling procedures, and 

business practices) that are developed or adopted by VCS

bodies. NTTAA directs the EPA to provide Congress, through 

OMB, explanations when the Agency decides not to use 

available and applicable VCS.

The proposed rule involves technical standards. 

Therefore, the requirements of the NTTAA apply to this 

action. We are proposing to revise 40 CFR part 63, subpart 

HH and 40 CFR part 63, subpart HHH to allow ANSI/ASME PTC 

19.10–1981, Flue and Exhaust Gas Analyses (Part 10, 

Instruments and Apparatus) to be used in lieu of EPA 

Methods 3B, 6 and 16A. This standard is available from the 

American Society of Mechanical Engineers (ASME), Three Park 

Avenue, New York, NY 10016-5990. Also, we are proposing to 

revise subpart HHH to allow ASTM D6420-99 (2004), Test 

Method for Determination of Gaseous Organic Compounds by 

Direct Interface Gas Chromatography/Mass Spectrometry, to 

be used in lieu of EPA Method 18. For a detailed discussion 

of this VCS, and its appropriateness as a substitute for 

Method 18, see the final Oil and Natural Gas Production 

NESHAP (Area Sources) (72 FR 36, January 3, 2007).
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As a result, the EPA is proposing ASTM D6420-99 (2004) 

for use in 40 CFR part 63, subpart HHH. The EPA also 

proposes to allow Method 18 as an option in addition to 

ASTM D6420-99 (2004). This would allow the continued use of 

gas chromatography configurations other than gas 

chromatography/mass spectrometry. 

The EPA welcomes comments on this aspect of the 

proposed rulemaking and, specifically, invites the public 

to identify potentially-applicable VCS and to explain why 

such standards should be used in this regulation.

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes Federal executive policy on EJ. Its main 

provision directs Federal agencies, to the greatest extent 

practicable and permitted by law, to make EJ part of their 

mission by identifying and addressing, as appropriate, 

disproportionately high and adverse human health or 

environmental effects of their programs, policies and 

activities on minority populations and low-income 

populations in the United States.
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The EPA has determined that this proposed rule will 

not have disproportionately high and adverse human health 

or environmental effects on minority or low-income 

populations because it increases the level of environmental 

protection for all affected populations without having any 

disproportionately high and adverse human health or 

environmental effects on any population, including any 

minority or low-income population.

To examine the potential for any EJ issues that might 

be associated with each source category, we evaluated the 

distributions of HAP-related cancer and noncancer risks 

across different social, demographic and economic groups 

within the populations living near the facilities where 

these source categories are located. The methods used to 

conduct demographic analyses for this rule are described in 

section VII.C of the preamble for this rule. The 

development of demographic analyses to inform the 

consideration of EJ issues in EPA rulemakings is an 

evolving science. The EPA offers the demographic analyses 

in this proposed rulemaking as examples of how such 

analyses might be developed to inform such consideration, 

and invites public comment on the approaches used and the 

interpretations made from the results, with the hope that 
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this will support the refinement and improve utility of 

such analyses for future rulemakings.

For the demographic analyses, we focused on the 

populations within 50 km of any facility estimated to have 

exposures to HAP which result in cancer risks of 1-in-1 

million or greater, or noncancer HI of 1 or greater (based 

on the emissions of the source category or the facility, 

respectively). We examined the distributions of those risks 

across various demographic groups, comparing the 

percentages of particular demographic groups to the total 

number of people in those demographic groups nationwide.

The results, including other risk metrics, such as average 

risks for the exposed populations, are documented in source 

category-specific technical reports in the docket for both 

source categories covered in this proposal.

As described in the preamble, our risk assessments 

demonstrate that the regulations for the oil and natural 

gas production and natural gas transmission and storage 

source categories, are associated with an acceptable level 

of risk and that the proposed additional requirements will 

provide an ample margin of safety to protect public health. 

Our analyses also show that, for these source categories, 

there is no potential for an adverse environmental effect 
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or human health multi-pathway effects, and that acute and 

chronic noncancer health impacts are unlikely. The EPA has 

determined that, although there may be an existing 

disparity in HAP risks from these sources between some 

demographic groups, no demographic group is exposed to an 

unacceptable level of risk.
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Standards of Performance for New Stationary Sources: Oil 

and Natural Gas Production and Natural Gas Transmission and 

Distribution; National Emission Standards for Hazardous Air 

Pollutants From Oil and Natural Gas Production Facilities; 

and National Emission Standards for Hazardous Air 

Pollutants From Natural Gas Transmission and Storage

Facilities--Page 342 of 601

List of Subjects in 40 CFR Part 60

Environmental protection, Air pollution control, Reporting 

and recordkeeping requirements, Volatile organic compounds.

List of Subjects in 40 CFR Part 63

Environmental protection, Air pollution control, Reporting 

and recordkeeping requirements, Volatile organic compounds.

____________________________

Dated:

____________________________

Lisa P. Jackson,

Administrator.
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For the reasons set out in the preamble, title 40, chapter 

I of the Code of Federal Regulations is proposed to be 

amended as follows:

PART 60--[AMENDED]

1. The authority citation for part 60 continues to 

read as follows:

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

2. Section 60.17 is amended by:

a. Revising paragraph (a)(7); and

b. Revising paragraphs (a)(91) and (a)(92) to read as 

follows:

§60.17 Incorporations by reference.

* * * * *

(a) * * *

(7) ASTM D86–78, 82, 90, 93, 95, 96, Distillation of 

Petroleum Products, IBR approved for §§60.562–2(d), 

60.593(d), 60.593a(d), 60.633(h) and 60.5401(h).

* * * * *

(91) ASTM E169–63, 77, 93, General Techniques of 

Ultraviolet Quantitative Analysis, IBR approved for 

§§60.485a(d)(1), 60.593(b)(2), 60.593a(b)(2), 60.632(f) and 

60.5400(f).
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(92) ASTM E260–73, 91, 96, General Gas Chromatography 

Procedures, IBR approved for §§60.485a(d)(1), 60.593(b)(2), 

60.593a(b)(2), 60.632(f), 60.5400(f) and 60.5406(b). 

* * * * *

Subpart KKK--Standards of Performance for Equipment Leaks 

of VOC From Onshore Natural Gas Processing Plants for which 

Construction, Reconstruction, or Modification Commenced

After January 20, 1984, and on or Before [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER].

3. The heading for Subpart KKK is revised as set out 

above.

4. Section 60.630 is amended by revising paragraph (b) 

to read as follows:

§60.630 Applicability and designation of affected facility.

* * * * *

(b) Any affected facility under paragraph (a) of this 

section that commences construction, reconstruction, or 

modification after January 20, 1984, and on or before 

[INSERT DATE OF PUBLICATON IN THE FEDERAL REGISTER], is 

subject to the requirements of this subpart.

* * * * *

Subpart LLL--Standards of Performance for SO2 Emissions 

from Onshore Natural Gas Processing for which Construction, 

Reconstruction, or Modification Commenced After January 20, 

1984, and on or Before [INSERT DATE OF PUBLICATION IN THE 

FEDERAL REGISTER].
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5. The heading for Subpart LLL is revised as set out 

above.

6. Section 60.640 is amended by revising paragraph (d)

to read as follows:

§60.640 Applicability and designation of affected 

facilities.

* * * * *

(d) The provisions of this subpart apply to each 

affected facility identified in paragraph (a) of this 

section which commences construction or modification after 

January 20, 1984, and on or before [INSERT DATE OF 

PUBLICATON IN THE FEDERAL REGISTER].

* * * * *

7. Part 60 is amended by adding subpart OOOO to read 

as follows:

Subpart OOOO—Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution.

Sec.

60.5360 What is the purpose of this subpart?

60.5365 Am I subject to this subpart?

60.5370 When must I comply with this subpart?

60.5375 What standards apply to gas wellhead affected 

facilities?

60.5380 What standards apply to centrifugal compressor 

affected facilities?

60.5385 What standards apply to reciprocating compressor 

affected facilities?
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60.5390 What standards apply to pneumatic controller 

affected facilities?

60.5395 What standards apply to storage vessel affected 

facilities?

60.5400 What VOC standards apply to affected facilities 

at an onshore natural gas processing plant?

60.5401 What are the exceptions to the VOC standards for 

affected facilities at onshore natural gas 

processing plants?

60.5402 What are the alternative emission limitations for 

affected facilities at onshore natural gas 

processing plants?

60.5405 What standards apply to sweetening units at 

onshore natural gas processing plants?

60.5406 What test methods and procedures must I use for 

my sweetening units affected facilities at 

onshore natural gas processing plants?

60.5407 What are the requirements for monitoring of 

emissions and operations from my sweetening unit 

affected facilities at onshore natural gas 

processing plants?

60.5408 What is an optional procedure for measuring H2S 

in acid gas-Tutwiler Procedure.

60.5410 How do I demonstrate initial compliance with the 

standards for my gas wellhead affected facility, 

my centrifugal compressor affected facility, my 

reciprocating compressor affected facility, my 

pneumatic controller affected facility, my 

storage vessel affected facility, and my affected 

facilities at onshore natural gas processing 

plants?

60.5415 How do I demonstrate continuous compliance with 

the standards for my gas wellhead affected 

facility, my centrifugal compressor affected 

facility, my reciprocating compressor affected 

facility, my pneumatic controller affected 

facility, my storage vessel affected facility, 

and my affected facilities at onshore natural gas 

processing plants?

60.5420 What are my notification, reporting, and 

recordkeeping requirements?

60.5421 What are my additional recordkeeping requirements

for my affected facility subject to VOC 

requirements for onshore natural gas processing 
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plants?

60.5422 What are my additional reporting requirements for 

my affected facility subject to VOC requirements 

for onshore natural gas processing plants?

60.5423 What additional recordkeeping and reporting 

requirements apply to my sweetening unit affected 

facilities at onshore natural gas processing 

plants?

60.5425 What part of the General Provisions apply to me?

60.5430 What definitions apply to this subpart?

Subpart OOOO—Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution.

§60.5360 What is the purpose of this subpart?

This subpart establishes emission standards and 

compliance schedules for the control of volatile organic 

compounds (VOC) and sulfur dioxide (SO2) emissions from 

affected facilities that commenced construction, 

modification or reconstruction after [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. 

§60.5365 Am I subject to this subpart?

If you are the owner or operator of one or more of the 

affected facilities listed in paragraphs (a) through (g) of 

this section that commenced construction, modification, or 

reconstruction after [INSERT DATE OF PUBLICATION IN THE 

FEDERAL REGISTER] your affected facility is subject to the 

applicable provisions of this subpart. For the purposes of 

this subpart, a well completion operation following 
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hydraulic fracturing or refracturing that occurs at a gas 

wellhead facility that commenced construction, 

modification, or reconstruction on or before [INSERT DATE 

OF PUBLICATION IN THE FEDERAL REGISTER] is considered a 

modification of the gas wellhead facility, but does not 

affect other equipment, process units, storage vessels, or 

pneumatic devices located at the well site. 

(a) A gas wellhead affected facility, is a single 

natural gas well. 

(b) A centrifugal compressor affected facility, which 

is defined as a single centrifugal compressor located 

between the wellhead and the city gate (as defined in 

§60.5430), except that a centrifugal compressor located at 

a well site (as defined in §60.5430) is not an affected 

facility under this subpart. For the purposes of this 

subpart, your centrifugal compressor is considered to have 

commenced construction on the date the compressor is 

installed at the facility.

(c) A reciprocating compressor affected facility, 

which is defined as a single reciprocating compressor 

located between the wellhead and the city gate (as defined 

in §60.5430), except that a reciprocating compressor 
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located at a well site (as defined in §60.5430) is not an 

affected facility under this subpart. For the purposes of 

this subpart, your reciprocating compressor is considered 

to have commenced construction on the date the compressor 

is installed at the facility.

(d) A pneumatic controller affected facility, which is 

defined as a single pneumatic controller.

(e) A storage vessel affected facility, which is 

defined as a single storage vessel.

(f) Compressors and equipment (as defined in §60.5430) 

located at onshore natural gas processing plants. 

(1) Each compressor in VOC service or in wet gas 

service is an affected facility.

(2) The group of all equipment, except compressors, 

within a process unit is an affected facility.

(3) Addition or replacement of equipment, as defined 

in §60.5430, for the purpose of process improvement that is 

accomplished without a capital expenditure shall not by 

itself be considered a modification under this subpart. 

 (4) Equipment (as defined in §60.5430) associated with 

a compressor station, dehydration unit, sweetening unit, 

underground storage tank, field gas gathering system, or 
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liquefied natural gas unit is covered by §§60.5400, 

60.5401, 60.5402, 60.5421 and 60.5422 of this subpart if it 

is located at an onshore natural gas processing plant. 

Equipment (as defined in §60.5430) not located at the 

onshore natural gas processing plant site is exempt from 

the provisions of §§60.5400, 60.5401, 60.5402, 60.5421 and 

60.5422 of this subpart.

(5) Affected facilities located at onshore natural gas 

processing plants and described in (f)(1) and (f)(2) are 

exempt from this subpart if they are subject to and 

controlled according to 40 CFR subparts VVa, GGG or GGGa.

(g) Sweetening units located onshore that process 

natural gas produced from either onshore or offshore wells.

(1) Each sweetening unit that processes natural gas is 

an affected facility; and

(2) Each sweetening unit that processes natural gas 

followed by a sulfur recovery unit is an affected facility.

(3) Facilities that have a design capacity less than 2 

long tons per day (LT/D) of hydrogen sulfide (H2S) in the 

acid gas (expressed as sulfur) are required to comply with 

recordkeeping and reporting requirements specified in 

§60.5423(c) but are not required to comply with §§60.5405
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through 60.5407 and paragraphs 60.5410(g) and 60.5415(g) of 

this subpart.

(4) Sweetening facilities producing acid gas that is 

completely reinjected into oil-or-gas-bearing geologic 

strata or that is otherwise not released to the atmosphere 

are not subject to §§60.5405 through 60.5407, and 

paragraphs 60.5410(g), 60.5415(g), and §60.5423 of this 

subpart.

§60.5370 When must I comply with this subpart?

(a) You must be in compliance with the standards of 

this subpart no later than the date of publication of the 

final rule in the Federal Register or upon startup, 

whichever is later. 

(b) The provisions for exemption from compliance 

during periods of startup, shutdown, and malfunctions 

provided for in 40 CFR 60.8(c) do not apply to this 

subpart.

(c) You are exempt from the obligation to obtain a 

permit under 40 CFR part 70 or 40 CFR part 71, provided you 

are not otherwise required by law to obtain a permit under 

40 CFR 70.3(a) or 40 CFR 71.3(a). Notwithstanding the 

previous sentence, you must continue to comply with the 
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provisions of this subpart.

§60.5375 What standards apply to gas wellhead affected 

facilities?

If you are the owner or operator of a gas wellhead 

affected facility, you must comply with paragraphs (a) 

through (g) of this section. 

(a) Except as provided in paragraph (f) of this 

section, for each well completion operation with hydraulic 

fracturing, as defined in §60.5430, you must control 

emissions by the operational procedures found in paragraphs 

(a)(1) through (a)(3) of this section.

(1) You must minimize the emissions associated with 

venting of hydrocarbon fluids and gas over the duration of 

flowback by routing the recovered liquids into storage 

vessels and routing the recovered gas into a gas gathering 

line or collection system.

(2) You must employ sand traps, surge vessels, 

separators, and tanks during flowback and cleanout 

operations to safely maximize resource recovery and 

minimize releases to the environment. All salable quality 

gas must be routed to the gas gathering line as soon as 

practicable.
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(3) You must capture and direct flowback emissions 

that cannot be directed to the gathering line to a 

completion combustion device, except in conditions that may 

result in a fire hazard or explosion. Completion combustion 

devices must be equipped with a reliable continuous 

ignition source over the duration of flowback.

 (b) You must maintain a log for each well completion 

operation at each gas wellhead affected facility. The log 

must be completed on a daily basis and must contain the 

records specified in §60.5420(c)(1)(iii).

 (c) You must demonstrate initial compliance with the 

standards that apply to gas wellhead affected facilities as 

required by §60.5410.

 (d) You must demonstrate continuous compliance with 

the standards that apply to gas wellhead affected 

facilities as required by §60.5415.

 (e) You must perform the required notification, 

recordkeeping, and reporting as required by §60.5420.

(f) For wells meeting the criteria for wildcat or 

delineation wells, each well completion operation with 

hydraulic fracturing at a gas wellhead affected facility 

must reduce emissions by using a completion combustion 
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device meeting the requirements of paragraph (a)(3) of this 

section. You must also maintain records specified in 

§60.5420(c)(1)(iii) for wildcat or delineation wells. 

§60.5380 What standards apply to centrifugal compressor 

affected facilities?

You must comply with the standards in paragraphs (a) 

through (d) of this section, as applicable for each 

centrifugal compressor affected facility.

(a) You must equip each rotating compressor shaft with 

a dry seal system upon initial startup. 

(b) You must demonstrate initial compliance with the 

standards that apply to centrifugal compressor affected 

facilities as required by §60.5410.

(c) You must demonstrate continuous compliance with 

the standards that apply to centrifugal compressor affected 

facilities as required by §60.5415.

(d) You must perform the required notification, 

recordkeeping, and reporting as required by §60.5420. 

§60.5385 What standards apply to reciprocating compressor 

affected facilities?

You must comply with the standards in paragraphs (a) 

through (d) of this section for each reciprocating 
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compressor affected facility.

(a) You must replace the reciprocating compressor rod 

packing before the compressor has operated for 26,000 

hours. The number of hours of operation must be 

continuously monitored beginning upon initial startup of 

your reciprocating compressor affected facility, or the 

date of publication of the final rule in the Federal 

Register, or the date of the previous reciprocating 

compressor rod packing replacement, whichever is later.

(b) You must demonstrate initial compliance with 

standards that apply to reciprocating compressor affected 

facilities as required by §60.5410.

(c) You must demonstrate continuous compliance with 

standards that apply to reciprocating compressor affected 

facilities as required by §60.5415.

(d) You must perform the required notification, 

recordkeeping, and reporting as required by §60.5420. 

§60.5390 What standards apply to pneumatic controller 

affected facilities?

For each pneumatic controller affected facility you 

must comply with the VOC standards, based on natural gas as 

a surrogate for VOC, in either paragraph (b) or (c) of this 
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section, as applicable. Pneumatic controllers meeting the 

conditions in paragraph (a) are exempt from this 

requirement.

(a) The requirements of paragraph (b) or (c) of this 

section are not required if you demonstrate, to the 

Administrator’s satisfaction, that the use of a high bleed 

device is predicated. The demonstration may include, but is 

not limited to, response time, safety and actuation. 

(b) Each pneumatic controller affected facility 

located at a natural gas processing plant (as defined in 

§60.5430) must have zero emissions of natural gas. 

(c) Each pneumatic controller affected facility not 

located at a natural gas processing plant (as defined in 

§60.5430) must have natural gas emissions no greater than 6 

standard cubic feet per hour.

(d) You must demonstrate initial compliance with 

standards that apply to pneumatic controller affected 

facilities as required by §60.5410.

(e) You must demonstrate continuous compliance with 

standards that apply to pneumatic controller affected 

facilities as required by §60.5415.

(f) You must perform the required notification, 
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recordkeeping, and reporting as required by §60.5420, 

except that you are not required to submit the 

notifications specified in §60.5420(a).

§60.5395 What standards apply to storage vessel affected 

facilities?

You must comply with the standards in paragraphs (a) 

through (e) of this section for each storage vessel

affected facility.

(a) You must comply with the standards for storage 

vessels specified in 40 CFR part 63, subpart HH, §63.766(b) 

and (c), except as specified in paragraph (b) of this 

section. Storage vessels that meet either one or both of 

the throughput conditions specified in paragraphs (a)(1) or 

(a)(2) of this section are not subject to the standards of 

this section. 

(1) The annual average condensate throughput is less 

than 1 barrel per day per storage vessel.

(2) The annual average crude oil throughput is less 

than 20 barrels per day per storage vessel.

(b) This standard does not apply to storage vessels 

already subject to and controlled in accordance with the 

requirements for storage vessels in 40 CFR part 63, subpart 
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HH, §63.766(b)(1) or (2).

(c) You must demonstrate initial compliance with 

standards that apply to storage vessel affected facilities 

as required by §60.5410.

(d) You must demonstrate continuous compliance with 

standards that apply to storage vessel affected facilities 

as required by §60.5415.

(e) You must perform the required notification, 

recordkeeping, and reporting as required by §60.5420.

§60.5400 What VOC standards apply to affected facilities at 

an onshore natural gas processing plant?

This section applies to each compressor in VOC service 

or in wet gas service and the group of all equipment (as 

defined in §60.5430), except compressors, within a process 

unit.

 (a) You must comply with the requirements of §60.482-

1a(a), (b), and (d),§60.482-2a, and §60.482-4a through 

60.482-11a, except as provided in §60.5401.

 (b) You may elect to comply with the requirements of 

§§60.483-1a and 60.483-2a, as an alternative.

 (c) You may apply to the Administrator for permission 

to use an alternative means of emission limitation that 
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achieves a reduction in emissions of VOC at least 

equivalent to that achieved by the controls required in 

this subpart according to the requirements of §60.5402 of 

this subpart.

 (d) You must comply with the provisions of §60.485a of 

this part except as provided in paragraph (f) of this 

section.

 (e) You must comply with the provisions of §§60.486a 

and 60.487a of this part except as provided in §§60.5401, 

60.5421, and 60.5422 of this part.

 (f) You must use the following provision instead of 

§60.485a(d)(1): Each piece of equipment is presumed to be 

in VOC service or in wet gas service unless an owner or 

operator demonstrates that the piece of equipment is not in 

VOC service or in wet gas service. For a piece of equipment 

to be considered not in VOC service, it must be determined 

that the VOC content can be reasonably expected never to 

exceed 10.0 percent by weight. For a piece of equipment to 

be considered in wet gas service, it must be determined 

that it contains or contacts the field gas before the 

extraction step in the process. For purposes of determining 

the percent VOC content of the process fluid that is 
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contained in or contacts a piece of equipment, procedures 

that conform to the methods described in ASTM E169-63, 77, 

or 93, E168-67, 77, or 92, or E260-73, 91, or 96 

(incorporated by reference as specified in §60.17) must be 

used.

§60.5401 What are the exceptions to the VOC standards for 

affected facilities at onshore natural gas processing 

plants?

 (a) You may comply with the following exceptions to the 

provisions of subpart VVa of this part.

 (b)(1) Each pressure relief device in gas/vapor service 

may be monitored quarterly and within 5 days after each 

pressure release to detect leaks by the methods specified 

in §60.485a(b) except as provided in §60.5400(c) and in

paragraph (b)(4) of this section, and §60.482-4a(a) through 

(c) of subpart VVa.

 (2) If an instrument reading of 5000 ppm or greater is 

measured, a leak is detected.

 (3)(i) When a leak is detected, it must be repaired as 

soon as practicable, but no later than 15 calendar days 

after it is detected, except as provided in §60.482-9a.

 (ii) A first attempt at repair must be made no later 
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than 5 calendar days after each leak is detected.

 (4)(i) Any pressure relief device that is located in a 

nonfractionating plant that is monitored only by non-plant 

personnel may be monitored after a pressure release the 

next time the monitoring personnel are on-site, instead of 

within 5 days as specified in paragraph (b)(1) of this 

section and §60.482-4a(b)(1) of subpart VVa.

 (ii) No pressure relief device described in paragraph 

(b)(4)(i) of this section must be allowed to operate for 

more than 30 days after a pressure release without 

monitoring.

 (c) Sampling connection systems are exempt from the 

requirements of §60.482-5a.

 (d) Pumps in light liquid service, valves in gas/vapor 

and light liquid service, and pressure relief devices in 

gas/vapor service that are located at a nonfractionating 

plant with a design capacity to process 283,200 standard 

cubic meters per day (scmd) (10 million standard cubic feet 

per day) or more of field gas are exempt from the routine 

monitoring requirements of §§60.482-2a(a)(1) and 60.482-

7a(a), and paragraph (b)(1) of this section.

 (e) Pumps in light liquid service, valves in gas/vapor 
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and light liquid service, and pressure relief devices in 

gas/vapor service within a process unit that is located in 

the Alaskan North Slope are exempt from the routine 

monitoring requirements of §§60.482-2a(a)(1), 60.482-7a(a), 

and paragraph (b)(1) of this section.

 (f) Flares used to comply with this subpart must comply 

with the requirements of §60.18.

 (g) An owner or operator may use the following 

provisions instead of §60.485a(e):

 (1) Equipment is in heavy liquid service if the weight 

percent evaporated is 10 percent or less at 150oC (302oF) as 

determined by ASTM Method D86-78, 82, 90, 95, or 96 

(incorporated by reference as specified in §60.17).

 (2) Equipment is in light liquid service if the weight 

percent evaporated is greater than 10 percent at 150oC 

(302oF) as determined by ASTM Method D86-78, 82, 90, 95, or 

96 (incorporated by reference as specified in §60.17).

§60.5402 What are the alternative emission limitations for 

equipment leaks from onshore natural gas processing plants?

 (a) If, in the Administrator's judgment, an alternative 

means of emission limitation will achieve a reduction in 

VOC emissions at least equivalent to the reduction in VOC 
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emissions achieved under any design, equipment, work 

practice or operational standard, the Administrator will 

publish, in the Federal Register, a notice permitting the 

use of that alternative means for the purpose of compliance 

with that standard. The notice may condition permission on 

requirements related to the operation and maintenance of 

the alternative means.

 (b) Any notice under paragraph (a) of this section must 

be published only after notice and an opportunity for a 

public hearing.

 (c) The Administrator will consider applications under 

this section from either owners or operators of affected 

facilities, or manufacturers of control equipment.

 (d) The Administrator will treat applications under 

this section according to the following criteria, except in 

cases where the Administrator concludes that other criteria 

are appropriate:

 (1) The applicant must collect, verify and submit test 

data, covering a period of at least 12 months, necessary to 

support the finding in paragraph (a) of this section.

 (2) If the applicant is an owner or operator of an 

affected facility, the applicant must commit in writing to 
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operate and maintain the alternative means so as to achieve 

a reduction in VOC emissions at least equivalent to the 

reduction in VOC emissions achieved under the design, 

equipment, work practice or operational standard.

§60.5405 What standards apply to sweetening units at 

onshore natural gas processing plants?

(a) During the initial performance test required by 

§60.8(b), you must achieve at a minimum, an SO2 emission 

reduction efficiency (Zi) to be determined from Table 1 of 

this subpart based on the sulfur feed rate (X) and the 

sulfur content of the acid gas (Y) of the affected 

facility.

(b) After demonstrating compliance with the provisions 

of paragraph (a) of this section, you must achieve at a 

minimum, an SO2 emission reduction efficiency (Zc) to be 

determined from Table 2 of this subpart based on the sulfur 

feed rate (X) and the sulfur content of the acid gas (Y) of 

the affected facility.

60.5406 What test methods and procedures must I use for my 

sweetening units affected facilities at onshore natural gas 

processing plants?

(a) In conducting the performance tests required in 
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§60.8, you must use the test methods in appendix A of this 

part or other methods and procedures as specified in this 

section, except as provided in paragraph §60.8(b).

(b) During a performance test required by §60.8, you 

must determine the minimum required reduction efficiencies 

(Z) of SO2 emissions as required in §60.5405(a) and (b) as 

follows:

(1) The average sulfur feed rate (X) must be computed 

as follows:

 = 

Where:

X = average sulfur feed rate, Mg/D (LT/D).

Qa = average volumetric flow rate of acid gas from 

sweetening unit, dscm/day (dscf/day).

Y = average H2S concentration in acid gas feed from 

sweetening unit, percent by volume, expressed as a decimal.

K = (32 kg S/kg-mole)/((24.04 dscm/kg-mole)(1000 kg S/ Mg))

 = 1.331 × 10−3Mg/dscm, for metric units

 = (32 lb S/lb-mole)/((385.36 dscf/lb-mole)(2240 lb S/long 

ton))

 = 3.707 × 10−5long ton/dscf, for English units.

(2) You must use the continuous readings from the 

process flowmeter to determine the average volumetric flow 

rate (Qa) in dscm/day (dscf/day) of the acid gas from the 

sweetening unit for each run.

(3) You must use the Tutwiler procedure in §60.5408 or 

a chromatographic procedure following ASTM E–260 
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(incorporated by reference—see §60.17) to determine the H2S 

concentration in the acid gas feed from the sweetening unit 

(Y). At least one sample per hour (at equally spaced 

intervals) must be taken during each 4-hour run. The 

arithmetic mean of all samples must be the average H2S 

concentration (Y) on a dry basis for the run. By 

multiplying the result from the Tutwiler procedure by 1.62 

× 10−3, the units gr/100 scf are converted to volume 

percent.

(4) Using the information from paragraphs (b)(1) and 

(b)(3) of this section, Tables 1 and 2 of this subpart must 

be used to determine the required initial (Zi) and 

continuous (Zc) reduction efficiencies of SO2 emissions.

(c) You must determine compliance with the SO2

standards in §60.5405(a) or (b) as follows:

(1) You must compute the emission reduction efficiency 

(R) achieved by the sulfur recovery technology for each run 

using the following equation:

 = (100) /( + )

(2) You must use the level indicators or manual 

soundings to measure the liquid sulfur accumulation rate in 

the product storage tanks. You must use readings taken at 
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the beginning and end of each run, the tank geometry, 

sulfur density at the storage temperature, and sample 

duration to determine the sulfur production rate (S) in 

kg/hr (lb/hr) for each run.

(3) You must compute the emission rate of sulfur for 

each run as follows:

 = /

Where:

E = emission rate of sulfur per run, kg/hr.

Ce = concentration of sulfur equivalent (SO2+ reduced 

sulfur), g/dscm (lb/dscf).

Qsd = volumetric flow rate of effluent gas, dscm/hr 

(dscf/hr).

K1 = conversion factor, 1000 g/kg (7000 gr/lb).

(4) The concentration (Ce) of sulfur equivalent must 

be the sum of the SO2 and TRS concentrations, after being 

converted to sulfur equivalents. For each run and each of 

the test methods specified in this paragraph (c) of this 

section, you must use a sampling time of at least 4 hours. 

You must use Method 1 of appendix A to part 60 of this 

chapter to select the sampling site. The sampling point in 

the duct must be at the centroid of the cross-section if 

the area is less than 5 m2 (54 ft2 ) or at a point no 

closer to the walls than 1 m (39 in) if the cross-sectional 
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area is 5 m2 or more, and the centroid is more than 1 m (39 

in.) from the wall.

(i) You must use Method 6 of appendix A to part 60 of 

this chapter to determine the SO2 concentration. You must 

take eight samples of 20 minutes each at 30-minute 

intervals. The arithmetic average must be the concentration 

for the run. The concentration must be multiplied by 0.5 × 

10−3 to convert the results to sulfur equivalent.

(ii) You must use Method 15 of appendix A to part 60 

of this chapter to determine the TRS concentration from 

reduction-type devices or where the oxygen content of the 

effluent gas is less than 1.0 percent by volume. The 

sampling rate must be at least 3 liters/min (0.1 ft3 /min) 

to insure minimum residence time in the sample line. You 

must take sixteen samples at 15-minute intervals. The 

arithmetic average of all the samples must be the 

concentration for the run. The concentration in ppm reduced 

sulfur as sulfur must be multiplied by 1.333 × 10−3 to 

convert the results to sulfur equivalent.

(iii) You must use Method 16A or Method 15 of appendix 

A to part 60 of this chapter to determine the reduced 

sulfur concentration from oxidation-type devices or where 
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the oxygen content of the effluent gas is greater than 1.0 

percent by volume. You must take eight samples of 20 

minutes each at 30-minute intervals. The arithmetic average 

must be the concentration for the run. The concentration in 

ppm reduced sulfur as sulfur must be multiplied by 1.333 × 

10−3 to convert the results to sulfur equivalent.

(iv) You must use Method 2 of appendix A to part 60 of 

this chapter to determine the volumetric flow rate of the 

effluent gas. A velocity traverse must be conducted at the 

beginning and end of each run. The arithmetic average of 

the two measurements must be used to calculate the 

volumetric flow rate (Qsd) for the run. For the 

determination of the effluent gas molecular weight, a 

single integrated sample over the 4-hour period may be 

taken and analyzed or grab samples at 1-hour intervals may 

be taken, analyzed, and averaged. For the moisture content, 

you must take two samples of at least 0.10 dscm (3.5 dscf) 

and 10 minutes at the beginning of the 4-hour run and near

the end of the time period. The arithmetic average of the 

two runs must be the moisture content for the run.

60.5407 What are the requirements for monitoring of 

emissions and operations from my sweetening unit affected 
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facilities at onshore natural gas processing plants?

(a) If your sweetening unit affected facility is 

located at an onshore natural gas processing plant and is 

subject to the provisions of §60.5405(a) or (b) you must 

install, calibrate, maintain, and operate monitoring 

devices or perform measurements to determine the following 

operations information on a daily basis:

(1) The accumulation of sulfur product over each 24-

hour period. The monitoring method may incorporate the use 

of an instrument to measure and record the liquid sulfur 

production rate, or may be a procedure for measuring and 

recording the sulfur liquid levels in the storage tanks 

with a level indicator or by manual soundings, with 

subsequent calculation of the sulfur production rate based 

on the tank geometry, stored sulfur density, and elapsed 

time between readings. The method must be designed to be 

accurate within ±2 percent of the 24-hour sulfur 

accumulation.

(2) The H2S concentration in the acid gas from the 

sweetening unit for each 24-hour period. At least one 

sample per 24-hour period must be collected and analyzed 

using the equation specified in §60.5406(b)(1). The 
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Administrator may require you to demonstrate that the H2S 

concentration obtained from one or more samples over a 24-

hour period is within ±20 percent of the average of 12 

samples collected at equally spaced intervals during the 

24-hour period. In instances where the H2S concentration of 

a single sample is not within ±20 percent of the average of 

the 12 equally spaced samples, the Administrator may 

require a more frequent sampling schedule.

(3) The average acid gas flow rate from the sweetening 

unit. You must install and operate a monitoring device to 

continuously measure the flow rate of acid gas. The 

monitoring device reading must be recorded at least once 

per hour during each 24-hour period. The average acid gas 

flow rate must be computed from the individual readings.

(4) The sulfur feed rate (X). For each 24-hour period, 

you must compute X using the equation specified in 

§60.5406(b)(3).

(5) The required sulfur dioxide emission reduction 

efficiency for the 24-hour period. You must use the sulfur 

feed rate and the H2S concentration in the acid gas for the 

24-hour period, as applicable, to determine the required 

reduction efficiency in accordance with the provisions of 
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§60.5405(b).

(b) Where compliance is achieved through the use of an 

oxidation control system or a reduction control system 

followed by a continually operated incineration device, you 

must install, calibrate, maintain, and operate monitoring 

devices and continuous emission monitors as follows:

(1) A continuous monitoring system to measure the 

total sulfur emission rate (E) of SO2 in the gases 

discharged to the atmosphere. The SO2 emission rate must be 

expressed in terms of equivalent sulfur mass flow rates 

(kg/hr (lb/hr)). The span of this monitoring system must be 

set so that the equivalent emission limit of §60.5405(b) 

will be between 30 percent and 70 percent of the 

measurement range of the instrument system.

(2) Except as provided in paragraph (b)(3) of this 

section: A monitoring device to measure the temperature of 

the gas leaving the combustion zone of the incinerator, if 

compliance with §60.5405(a) is achieved through the use of 

an oxidation control system or a reduction control system 

followed by a continually operated incineration device. The 

monitoring device must be certified by the manufacturer to 

be accurate to within ±1 percent of the temperature being 
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measured.

(3) When performance tests are conducted under the 

provision of §60.8 to demonstrate compliance with the 

standards under §60.5405, the temperature of the gas 

leaving the incinerator combustion zone must be determined 

using the monitoring device. If the volumetric ratio of 

sulfur dioxide to sulfur dioxide plus total reduced sulfur 

(expressed as SO2) in the gas leaving the incinerator is 

equal to or less than 0.98, then temperature monitoring may 

be used to demonstrate that sulfur dioxide emission 

monitoring is sufficient to determine total sulfur 

emissions. At all times during the operation of the 

facility, you must maintain the average temperature of the 

gas leaving the combustion zone of the incinerator at or 

above the appropriate level determined during the most 

recent performance test to ensure the sulfur compound 

oxidation criteria are met. Operation at lower average 

temperatures may be considered by the Administrator to be 

unacceptable operation and maintenance of the affected 

facility. You may request that the minimum incinerator 

temperature be reestablished by conducting new performance 

tests under §60.8.
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(3) Upon promulgation of a performance specification 

of continuous monitoring systems for total reduced sulfur 

compounds at sulfur recovery plants, you may, as an 

alternative to paragraph (b)(2) of this section, install, 

calibrate, maintain, and operate a continuous emission 

monitoring system for total reduced sulfur compounds as 

required in paragraph (d) of this section in addition to a 

sulfur dioxide emission monitoring system. The sum of the 

equivalent sulfur mass emission rates from the two 

monitoring systems must be used to compute the total sulfur 

emission rate (E).

(c) Where compliance is achieved through the use of a 

reduction control system not followed by a continually 

operated incineration device, you must install, calibrate, 

maintain, and operate a continuous monitoring system to 

measure the emission rate of reduced sulfur compounds as 

SO2 equivalent in the gases discharged to the atmosphere. 

The SO2 equivalent compound emission rate must be expressed 

in terms of equivalent sulfur mass flow rates (kg/hr 

(lb/hr)). The span of this monitoring system must be set so 

that the equivalent emission limit of §60.5405(b) will be 

between 30 and 70 percent of the measurement range of the 
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system. This requirement becomes effective upon 

promulgation of a performance specification for continuous 

monitoring systems for total reduced sulfur compounds at 

sulfur recovery plants.

(d) For those sources required to comply with 

paragraph (b) or (c) of this section, you must calculate 

the average sulfur emission reduction efficiency achieved 

(R) for each 24-hour clock internal. The 24-hour interval 

may begin and end at any selected clock time, but must be 

consistent. You must compute the 24-hour average reduction 

efficiency (R) based on the 24-hour average sulfur 

production rate (S) and sulfur emission rate (E), using the 

equation in §60.5406(c)(1).

(1) You must use data obtained from the sulfur 

production rate monitoring device specified in paragraph 

(a) of this section to determine S.

(2) You must use data obtained from the sulfur 

emission rate monitoring systems specified in paragraphs 

(b) or (c) of this section to calculate a 24-hour average 

for the sulfur emission rate (E). The monitoring system 

must provide at least one data point in each successive 15-

minute interval. You must use at least two data points to 
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calculate each 1-hour average. You must use a minimum of 18 

1-hour averages to compute each 24-hour average.

(e) In lieu of complying with (b) or (c) of this 

section, those sources with a design capacity of less than 

152 Mg/D (150 LT/D) of H2S expressed as sulfur may calculate 

the sulfur emission reduction efficiency achieved for each 

24-hour period by:

 =





Where:

R = The sulfur dioxide removal efficiency achieved during 

the 24-hour period, percent.

K2 = Conversion factor, 0.02400 Mg/D per kg/hr (0.01071 

LT/D per lb/hr).

S = The sulfur production rate during the 24-hour period, 

kg/hr (lb/hr).

X = The sulfur feed rate in the acid gas, Mg/D (LT/D).

(f) The monitoring devices required in paragraphs 

(b)(1), (b)(3) and (c) of this section must be calibrated 

at least annually according to the manufacturer's 

specifications, as required by §60.13(b).

(g) The continuous emission monitoring systems 

required in paragraphs (b)(1), (b)(3), and (c) of this 

section must be subject to the emission monitoring 

requirements of §60.13 of the General Provisions. For 

conducting the continuous emission monitoring system 
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performance evaluation required by §60.13(c), Performance 

Specification 2 of appendix B to part 60 of this chapter 

must apply, and Method 6 must be used for systems required 

by paragraph (b) of this section.

§60.5408 What is an optional procedure for measuring 

hydrogen sulfide in acid gas—Tutwiler Procedure.52

(a) When an instantaneous sample is desired and H2S 

concentration is ten grains per 1000 cubic foot or more, a 

100 ml Tutwiler burette is used. For concentrations less 

than ten grains, a 500 ml Tutwiler burette and more dilute 

solutions are used. In principle, this method consists of 

titrating hydrogen sulfide in a gas sample directly with a 

standard solution of iodine.

(b) Apparatus. (See Figure 1 of this subpart) A 100 

or 500 ml capacity Tutwiler burette, with two-way glass 

stopcock at bottom and three-way stopcock at top which 

connect either with inlet tubulature or glass-stoppered 

cylinder, 10 ml capacity, graduated in 0.1 ml subdivision; 

rubber tubing connecting burette with leveling bottle.

(c) Reagents. (1) Iodine stock solution, 0.1N. Weight 

 

55 Gas Engineers Handbook, Fuel Gas Engineering practices, The 

Industrial Press, 93 Worth Street, New York, NY, 1966, First 

Edition, Second Printing, page 6/25 (Docket A-80-20-A, Entry III-67).
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12.7 g iodine, and 20 to 25 g cp potassium iodide for each 

liter of solution. Dissolve KI in as little water as 

necessary; dissolve iodine in concentrated KI solution, 

make up to proper volume, and store in glass-stoppered 

brown glass bottle.

(2) Standard iodine solution, 1 ml=0.001771 g I. 

Transfer 33.7 ml of above 0.1N stock solution into a 250 ml 

volumetric flask; add water to mark and mix well. Then, for 

100 ml sample of gas, 1 ml of standard iodine solution is 

equivalent to 100 grains H2S per cubic feet of gas.

(3) Starch solution. Rub into a thin paste about one 

teaspoonful of wheat starch with a little water; pour into 

about a pint of boiling water; stir; let cool and decant 

off clear solution. Make fresh solution every few days.

(d) Procedure. Fill leveling bulb with starch 

solution. Raise (L), open cock (G), open (F) to (A), and 

close (F) when solutions starts to run out of gas inlet. 

Close (G). Purge gas sampling line and connect with (A). 

Lower (L) and open (F) and (G). When liquid level is 

several ml past the 100 ml mark, close (G) and (F), and 

disconnect sampling tube. Open (G) and bring starch 

solution to 100 ml mark by raising (L); then close (G). 
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Open (F) momentarily, to bring gas in burette to 

atmospheric pressure, and close (F). Open (G), bring liquid 

level down to 10 ml mark by lowering (L). Close (G), clamp 

rubber tubing near (E) and disconnect it from burette. 

Rinse graduated cylinder with a standard iodine solution 

(0.00171 g I per ml); fill cylinder and record reading. 

Introduce successive small amounts of iodine thru (F); 

shake well after each addition; continue until a faint 

permanent blue color is obtained. Record reading; subtract 

from previous reading, and call difference D.

(e) With every fresh stock of starch solution perform 

a blank test as follows: Introduce fresh starch solution 

into burette up to 100 ml mark. Close (F) and (G). Lower 

(L) and open (G). When liquid level reaches the 10 ml mark, 

close (G). With air in burette, titrate as during a test 

and up to same end point. Call ml of iodine used C. Then,

Grains H2S per 100 cubic foot of gas=100 (D—C)

(f) Greater sensitivity can be attained if a 500 ml 

capacity Tutwiler burette is used with a more dilute 

(0.001N) iodine solution. Concentrations less than 1.0 

grains per 100 cubic foot can be determined in this way. 

Usually, the starch-iodine end point is much less distinct, 
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and a blank determination of end point, with H2S-free gas 

or air, is required.

Figure 1. Tutwiler burette (lettered items mentioned in 

text).

§60.5410 How do I demonstrate initial compliance with the 
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standards for my gas wellhead affected facility, my 

centrifugal compressor affected facility, my reciprocating 

compressor affected facility, my pneumatic controller 

affected facility, my storage vessel affected facility, and 

my affected facilities at onshore natural gas processing 

plants?

You must determine initial compliance with the 

standards for each affected facility using the requirements 

in paragraphs (a) through (g) of this section. The initial 

compliance period begins on the date of publication of the 

final rule in the Federal Register or upon initial startup, 

whichever is later, and ends on the date the first annual 

report is due as specified in §60.5420(b).

(a) You have achieved initial compliance with 

standards for each well completion operation conducted at 

your gas wellhead affected facility if you have complied 

with paragraphs (a)(1) and (a)(2) of this section.

(1) You have notified the Administrator within 30 days 

of the commencement of the well completion operation, the 

date of the commencement of the well completion operation, 

the latitude and longitude coordinates of the well in 

decimal degrees to an accuracy and precision of five (5) 
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decimals of a degree using the North American Datum (NAD) 

of 1983.

(2) You have maintained a log of records as specified 

in §60.5375(b) or (f) for each well completion operation 

conducted during the initial compliance period.

(3) You have submitted the initial annual report for 

your wellhead affected facility as required in §60.5420(b).

(b) You have achieved initial compliance with 

standards for your centrifugal compressor affected facility 

if the centrifugal compressor is fitted with a dry seal 

system upon initial startup as required by §60.5380.

(c) You have achieved initial compliance with 

standards for each reciprocating compressor affected 

facility if you have complied with paragraphs (c)(1) and 

(c)(2) of this section.

(1) During the initial compliance period, you have 

continuously monitored the number of hours of operation. 

(2) You have included the cumulative number of hours 

of operation for your reciprocating compressor affected 

facility during the initial compliance period in your 

initial annual report required in §60.5420(b).

(d) You have achieved initial compliance with emission 
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standards for your pneumatic controller affected facility 

if you comply with the requirements specified in paragraphs 

(d)(1) through (d)(4) of this section.

(1) You have demonstrated, to the Administrator’s 

satisfaction, the use of a high bleed device is predicated 

as specified in §60.5490(a).

(2) You own or operate a pneumatic controller affected 

facility located at a natural gas processing plant and your 

pneumatic controller is driven other than by use of natural 

gas and therefore emits zero natural gas. 

(3) You own or operate a pneumatic controller affected 

facility not located at a natural gas processing plant and 

the manufacturer’s design specifications guarantee the 

controller emits less than or equal to 6.0 standard cubic 

feet of gas per hour.

(4) You have included the information in paragraphs 

(d)(1) through (d)(3) of this section in the initial annual 

report submitted for your pneumatic controller affected 

facilities according to the requirements of §60.5420(b).

(e) You have demonstrated initial compliance with 

emission standards for your storage vessel affected 

facility if you are complying with paragraphs (e)(1) 
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through (e)(7) of this section.

(1) You have equipped the storage vessel with a closed 

vent system that meets the requirements of §63.771(c) 

connected to a control device that meets the conditions 

specified in §63.771(d).

(2) You have conducted an initial performance test as 

required in §63.772(e) within 180 days after initial 

startup or the date of publication of the final rule in the 

Federal Register and have conducted the compliance 

demonstration in §63.772(f).

(3) You have conducted the initial inspections 

required in §63.773(c).

(4) You have installed and operated continuous 

parameter monitoring systems in accordance with §63.773(d).

(5) If you are exempt from the standards of §60.5395 

according to §60.5395(a)(1) or (a)(2), you have determined 

the condensate or crude oil throughput, as applicable, 

according to paragraphs (e)(5)(i) or (e)(5)(ii) of this 

section and demonstrated to the Administrator’s 

satisfaction that your annual average condensate throughput 

is less than 1 barrel per day per tank and your annual 

average crude oil throughput is less than 20 barrels per 
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day per tank.

(i) You have installed and operated a flow meter to 

measure condensate or crude oil throughput in accordance 

with the manufacturer’s procedures or specifications.

(ii) You have used any other method approved by the 

Administrator to determine annual average condensate or 

crude oil throughput.

(6) You have submitted the information in paragraphs 

(e)(1) through (e)(5) of this section in the initial annual 

report for your storage vessel affected facility as 

required in §60.5420(b). 

(f) For affected facilities at onshore natural gas 

processing plants, initial compliance with the VOC 

requirements is demonstrated if you are in compliance with 

the requirements of §60.5400.

(g) For sweetening unit affected facilities at onshore 

natural gas processing plants, initial compliance is 

demonstrated according to paragraphs (g)(1) through (g)(3) 

of this section.

(1) To determine compliance with the standards for SO2

specified in §60.5405(a), during the initial performance 

test as required by §60.8, the minimum required sulfur 
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dioxide emission reduction efficiency (Zi) is compared to 

the emission reduction efficiency (R) achieved by the 

sulfur recovery technology as specified in paragraphs 

(g)(1)(i) and (g)(1)(ii) of this section.

(i) If R ≥ Zi, your affected facility is in compliance.

(ii) If R < Zi, your affected facility is not in 

compliance.

(2) The emission reduction efficiency (R) achieved by 

the sulfur reduction technology must be determined using 

the procedures in §60.5406(c)(1).

(3) You have submitted the results of paragraphs 

(g)(1) and (g)(2) in the initial annual report submitted 

for your sweetening unit affected facilities at onshore 

natural gas processing plants. 

§60.5415 How do I demonstrate continuous compliance with 

the standards for my gas wellhead affected facility, my 

centrifugal compressor affected facility, my stationary 

reciprocating compressor affected facility, my pneumatic 

controller affected facility, my storage vessel affected 

facility, and my affected facilities at onshore natural gas 

processing plants?

(a) For each gas wellhead affected facility, you must 
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demonstrate continuous compliance by maintaining the 

records for each completion operation (as defined in 

§60.5430) specified in §60.5420.

(b) For each centrifugal compressor affected 

facility, continuous compliance is demonstrated if the 

rotating compressor shaft is equipped with a dry seal.

(c) For each reciprocating compressor affected 

facility, you have demonstrated continuous compliance 

according to paragraphs (c)(1) and (2) of this section

(1) You have continuously monitored the number of 

hours of operation for each reciprocating compressor 

affected facility since initial startup, or the date of 

publication of the final rule in the Federal Register, or 

the date of the previous reciprocating compressor rod 

packing replacement, whichever is later. The cumulative 

number of hours of operation must be included in the annual 

report as required in §60.5420(b)(4).

(2) You have replaced the reciprocating compressor rod 

packing before the total number of hours of operation 

reaches 26,000 hours.

(d) For each pneumatic controller affected facility, 

continuous compliance is demonstrated by maintaining the 
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records demonstrating that you have installed and operated 

the pneumatic controllers as required in §60.5390(a), (b) 

or (c).

(e) For each storage vessel affected facility, 

continuous compliance is demonstrated according 40 CFR part 

63, subpart HH, §63.772(f).

(f) For affected facilities at onshore natural gas 

processing plants, continuous compliance with VOC 

requirements is demonstrated if you are in compliance with 

the requirements of §60.5400.

(g) For each sweetening unit affected facility at 

onshore natural gas processing plants, you must demonstrate 

continuous compliance with the standards for SO2 specified 

in §60.5405(b) according to paragraphs (g)(1) and (g)(2) of 

this section.

(1) The minimum required SO2 emission reduction 

efficiency (Zc) is compared to the emission reduction 

efficiency (R) achieved by the sulfur recovery technology.

(i) If R ≥ Zc, your affected facility is in compliance.

(ii) If R < Zc, your affected facility is not in 

compliance.

(2) The emission reduction efficiency (R) achieved by 
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the sulfur reduction technology must be determined using 

the procedures in §60.5406(c)(1).

(h) Affirmative Defense for Exceedance of Emission 

Limit During Malfunction. In response to an action to 

enforce the standards set forth in paragraph §§60.5375, 

60.5380, 60.5385, 60.5390, 60.5395, 60.5400, and 60.5405, 

you may assert an affirmative defense to a claim for civil 

penalties for exceedances of such standards that are caused 

by malfunction, as defined at 40 CFR 60.2. Appropriate 

penalties may be assessed, however, if you fail to meet 

your burden of proving all of the requirements in the 

affirmative defense. The affirmative defense shall not be 

available for claims for injunctive relief.

(1) To establish the affirmative defense in any action 

to enforce such a limit, you must timely meet the 

notification requirements in §60.5420(a), and must prove by 

a preponderance of evidence that:

(i) The excess emissions: 

(A) Were caused by a sudden, infrequent, and 

unavoidable failure of air pollution control and monitoring 

equipment, process equipment, or a process to operate in a 

normal or usual manner, and 
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(B) Could not have been prevented through careful 

planning, proper design or better operation and maintenance 

practices; and

(C) Did not stem from any activity or event that could 

have been foreseen and avoided, or planned for; and

(D) Were not part of a recurring pattern indicative of 

inadequate design, operation, or maintenance; and

(ii) Repairs were made as expeditiously as possible 

when the applicable emission limitations were being 

exceeded. Off-shift and overtime labor were used, to the 

extent practicable to make these repairs; and

(iii) The frequency, amount and duration of the excess 

emissions (including any bypass) were minimized to the 

maximum extent practicable during periods of such 

emissions; and

(iv) If the excess emissions resulted from a bypass of 

control equipment or a process, then the bypass was 

unavoidable to prevent loss of life, personal injury, or 

severe property damage; and

(v) All possible steps were taken to minimize the 

impact of the excess emissions on ambient air quality, the 

environment and human health; and
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(vi) All emissions monitoring and control systems were 

kept in operation if at all possible, consistent with 

safety and good air pollution control practices; and

(vii) All of the actions in response to the excess 

emissions were documented by properly signed, 

contemporaneous operating logs; and

(viii) At all times, the facility was operated in a 

manner consistent with good practices for minimizing 

emissions; and

(ix) A written root cause analysis has been prepared, 

the purpose of which is to determine, correct, and 

eliminate the primary causes of the malfunction and the 

excess emissions resulting from the malfunction event at 

issue. The analysis shall also specify, using best 

monitoring methods and engineering judgment, the amount of 

excess emissions that were the result of the malfunction. 

(2) The owner or operator of the facility experiencing 

an exceedance of its emission limit(s) during a malfunction 

shall notify the Administrator by telephone or facsimile 

(FAX) transmission as soon as possible, but no later than 2 

business days after the initial occurrence of the 

malfunction, if it wishes to avail itself of an affirmative 
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defense to civil penalties for that malfunction. The owner 

or operator seeking to assert an affirmative defense shall 

also submit a written report to the Administrator within 45 

days of the initial occurrence of the exceedance of the 

standards in §§60.5375, 60.5380, 60.5385, 60.5390, 60.5395, 

and 60.5400 to demonstrate, with all necessary supporting 

documentation, that it has met the requirements set forth 

in paragraph (a) of this section. The owner or operator may 

seek an extension of this deadline for up to 30 additional 

days by submitting a written request to the Administrator 

before the expiration of the 45-day period. Until a request 

for an extension has been approved by the Administrator, 

the owner or operator is subject to the requirement to 

submit such report within 45 days of the initial occurrence 

of the exceedance.

§60.5420 What are my notification, reporting, and 

recordkeeping requirements?

(a) You must submit the notifications required in 

§60.7(a)(1), (a)(3) and (a)(4), and according to paragraphs 

(a)(1) and (a)(2) of this section, if you own or operate 

one or more of the affected facilities specified in 

§60.5365. For the purposes of this subpart, a workover that 
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occurs after [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER] at each affected facility for which construction, 

reconstruction, or modification commenced on or before 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] is 

considered a modification for which a notification must be 

submitted under §60.7(a)(4).

(1) If you own or operate a pneumatic controller 

affected facility you are not required to submit the 

notifications required in §60.7(a)(1), (a)(3) and (a)(4).

(2) If you own or operate a gas wellhead affected 

facility, you must submit a notification to the 

Administrator within 30 days of the commencement of the 

well completion operation. The notification must include 

the date of commencement of the well completion operation, 

the latitude and longitude coordinates of the well in 

decimal degrees to an accuracy and precision of five (5) 

decimals of a degree using the North American Datum of 

1983.

(b) Reporting requirements. You must submit annual 

reports containing the information specified in paragraphs 

(b)(1) through (b)(6) of this section to the Administrator. 

The initial annual report is due 1 year after the initial 
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startup date for your affected facility or 1 year after the 

date of publication of the final rule in the Federal 

Register, whichever is later. Subsequent annual reports are 

due on the same date each year as the initial annual 

report. If you own or operate more than one affected 

facility, you may submit one report for multiple affected 

facilities provided the report contains all of the 

information required as specified in paragraphs (b)(1) 

through (b)(6) of this section.

(1) The general information specified in paragraphs 

(b)(1)(i) through (b)(1)(iii) of this section.

(i) The company name and address of the affected 

facility. 

(ii) An identification of each affected facility being 

included in the annual report.

(iii) Beginning and ending dates of the reporting 

period.

(2) For each gas wellhead affected facility, the 

information in paragraphs (b)(2)(i) through (b)(2)(iii) of 

this section.

(i) An identification of each well completion 

operation, as defined in §60.5430, for each gas wellhead 
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affected facility conducted during the reporting period;

(ii) A record of deviations in cases where well 

completion operations with hydraulic fracturing were not 

performed in compliance with the requirements specified in 

§60.5375 for each gas well affected facility. 

(iii) Records specified in §60.5375(b) for each well 

completion operation that occurred during the reporting 

period. 

(3) For each centrifugal compressor affected facility 

installed during the reporting period, documentation that 

the centrifugal compressor is equipped with dry seals.

(4) For each reciprocating compressor affected 

facility, the information specified in paragraphs (b)(4)(i) 

and (b)(4)(ii) of this section.

(i) The cumulative number of hours or operation since 

initial startup, the date of publication of the final rule 

in the Federal Register, or since the previous 

reciprocating compressor rod packing replacement, whichever 

is later.

(ii) Documentation that the reciprocating compressor 

rod packing was replaced before the cumulative number of 

hours of operation reached 24,000 hours.
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(5) For each pneumatic controller affected facility, 

the information specified in paragraphs (b)(5)(i) through 

(b)(5)(iv) of this section.

(i) The date, location and manufacturer specifications 

for each pneumatic controller installed.

(ii) If applicable, documentation that the use of high 

bleed pneumatic devices is predicated and the reasons why.

(iii) For pneumatic controllers not installed at a 

natural gas processing plant, the manufacturer’s guarantee 

that the device is designed such that natural gas emissions 

are less than 6 standard cubic feet per hour.

(iv) For pneumatic controllers installed at a natural 

gas processing plant, documentation that each controllers 

has zero natural gas emissions.

(6) For each storage vessel affected facility, the 

information in paragraphs (b)(6)(i) and (b)(6)(ii) of this 

section.

(i) If required to reduce emissions by complying with 

paragraph §60.5395(a)(1), the records specified in 40 CFR 

part 63, subpart §63.774(b)(2) through (b)(8).

(ii) Documentation that the annual average condensate 

throughput is less than 1 barrel per day per storage vessel 
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and crude oil throughput is less than 21 barrels per day 

per storage for meeting the requirements in §60.5395(a)(1) 

or (a)(2).

(c) Recordkeeping requirements. You must maintain the 

records identified as specified in §60.7(f) and in 

paragraphs (c)(1) through (c)(5) of this section

(1) The records for each gas wellhead affected 

facility as specified in paragraphs (c)(1)(i) through 

(c)(1)(iii).

(i) Records identifying each well completion operation 

for each gas wellhead affected facility conducted during 

the reporting period;

(ii) Record of deviations in cases where well 

completion operations with hydraulic fracturing were not 

performed in compliance with the requirements specified in 

§60.5375.

(iii) Records required in §60.5375(b) or (f) for each 

well completion operation conducted for each gas wellhead 

affected facility that occurred during the reporting 

period. You must maintain the records specified in 

paragraphs (c)(1)(iii)(A) and (c)(1)(iii)(B) of this 

section.
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(A) For each gas wellheads affected facility required 

to comply with the requirements of §60.5375(a), you must 

record: The location of the well; the duration of flowback; 

duration of recovery to the sales line; duration of 

combustion; duration of venting; and specific reasons for 

venting in lieu of capture or combustion. The duration must 

be specified in hours of time.

(B) For each gas wellhead affected facility required 

to comply with the requirements of §60.5375(f), you must 

maintain the records specified in paragraph (c)(1)(iii)(A) 

of this section except that you do not have to record the 

duration of recovery to the sales line. In addition, you 

must record the distance, in miles, of the nearest 

gathering line.

(2) For each centrifugal compressor affected facility, 

you must maintain records on the type of seal system 

installed.

(3) For each reciprocating compressors affected 

facility, you must maintain the records in paragraphs 

(c)(3)(i) and (c)(3)(ii) of this section.

(i) Records of the cumulative number of hours of 

operation since initial startup or the date of publication 
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of the final rule in the Federal Register, or the previous 

replacement of the reciprocating compressor rod packing, 

whichever is later.

(ii) Records of the date and time of each 

reciprocating compressor rod packing replacement.

(4) For each pneumatic controller affected facility, 

you must maintain the records identified in paragraphs 

(c)(4)(i) through (c)(4)(iv) of this section.

(i) Records of the date, location and manufacturer 

specifications for each pneumatic controller installed.

(ii) Records of the determination that the use of high 

bleed pneumatic devices is predicated and the reasons why.

(iii) If the pneumatic controller affected facility is 

not located at a natural gas processing plant, records of 

the manufacturer’s guarantee that the device is designed 

such that natural gas emissions are less than 6 standard 

cubic feet per hour.

(iv) If the pneumatic controller affected facility is 

located at a natural gas processing plant, records of the 

documentation that only instrument air controllers are 

used.

(5) For each storage vessel affected facility, you 
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must maintain the records identified in paragraphs 

(c)(5)(i) and (c)(5)(ii) of this section.

(i) If required to reduce emissions by complying with 

§63.766, the records specified in 40 CFR part 63, subpart 

HH, §63.774(b)(2) through (8).

(ii) Records of the determination that the annual 

average condensate throughput is less than 1 barrel per day 

per storage vessel and crude oil throughput is less than 21 

barrels per day per storage vessel for the exemption under 

§60.5395(a)(1) and (a)(2).

§60.5421 What are my additional recordkeeping requirements 

for my affected facility subject to VOC requirements for 

onshore natural gas processing plants?

(a) You must comply with the requirements of paragraph 

(b)of this section in addition to the requirements of 

§60.486a.

 (b) The following recordkeeping requirements apply to 

pressure relief devices subject to the requirements of 

§60.5401(b)(1) of this subpart.

 (1) When each leak is detected as specified in 

§60.5401(b)(2), a weatherproof and readily visible 

identification, marked with the equipment identification 
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number, must be attached to the leaking equipment. The 

identification on the pressure relief device may be removed 

after it has been repaired.

 (2) When each leak is detected as specified in 

§60.5401(b)(2), the following information must be recorded 

in a log and shall be kept for 2 years in a readily 

accessible location:

 (i) The instrument and operator identification numbers 

and the equipment identification number.

 (ii) The date the leak was detected and the dates of 

each attempt to repair the leak.

 (iii) Repair methods applied in each attempt to repair 

the leak.

 (iv) ”Above 500 ppm” if the maximum instrument reading 

measured by the methods specified in paragraph (a) of this 

section after each repair attempt is 500 ppm or greater.

 (v) ”Repair delayed” and the reason for the delay if a 

leak is not repaired within 15 calendar days after 

discovery of the leak.

 (vi) The signature of the owner or operator (or 

designate) whose decision it was that repair could not be 

effected without a process shutdown.
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 (vii) The expected date of successful repair of the 

leak if a leak is not repaired within 15 days.

 (viii) Dates of process unit shutdowns that occur while 

the equipment is unrepaired.

 (ix) The date of successful repair of the leak.

 (x) A list of identification numbers for equipment that 

are designated for no detectable emissions under the 

provisions of §60.482-4a(a). The designation of equipment 

subject to the provisions of §60.482-4a(a) must be signed 

by the owner or operator.

§60.5422 What are my additional reporting requirements for 

my affected facility subject to VOC requirements for 

onshore natural gas processing plants?

(a) You must comply with the requirements of 

paragraphs (b) and (c) of this section in addition to the 

requirements of §60.487a(a), (b), (c)(i) through (iv), and 

(c)(vii) through (viii).

(b) An owner or operator must include the following 

information in the initial semiannual report in addition to 

the information required in §60.487a(b)(1) through (4): 

Number of pressure relief devices subject to the 

requirements of §60.5401(b) except for those pressure 
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relief devices designated for no detectable emissions under 

the provisions of §60.482–4a(a) and those pressure relief 

devices complying with §60.482–4a(c).

(c) An owner or operator must include the following 

information in all semiannual reports in addition to the 

information required in §60.487a(c)(2)(i) through (vi):

(1) Number of pressure relief devices for which leaks 

were detected as required in §60.5401(b)(2); and

(2) Number of pressure relief devices for which leaks 

were not repaired as required in §60.5401(b)(3).

§60.5423 What additional recordkeeping and reporting 

requirements apply to my sweetening unit affected 

facilities at onshore natural gas processing plants?

(a) You must retain records of the calculations and 

measurements required in §60.5405(a) and (b) and 

§60.5407(a) through (g) for at least 2 years following the 

date of the measurements. This requirement is included 

under §60.7(d) of the General Provisions.

(b) You must submit a written report of excess 

emissions to the Administrator semiannually. For the 

purpose of these reports, excess emissions are defined as:

(1) Any 24-hour period (at consistent intervals) 
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during which the average sulfur emission reduction 

efficiency (R) is less than the minimum required efficiency 

(Z).

(2) For any affected facility electing to comply with 

the provisions of §60.5407(b)(2), any 24-hour period during 

which the average temperature of the gases leaving the 

combustion zone of an incinerator is less than the 

appropriate operating temperature as determined during the 

most recent performance test in accordance with the 

provisions of §60.5407(b)(2). Each 24-hour period must 

consist of at least 96 temperature measurements equally 

spaced over the 24 hours.

(c) To certify that a facility is exempt from the 

control requirements of these standards, for each facility 

with a design capacity less that 2 LT/D of H2S in the acid 

gas (expressed as sulfur) you must keep, for the life of 

the facility, an analysis demonstrating that the facility's 

design capacity is less than 2 LT/D of H2S expressed as 

sulfur.

(d) If you elect to comply with §60.5407(e) you must 

keep, for the life of the facility, a record demonstrating 

that the facility's design capacity is less than 150 LT/D 
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of H2S expressed as sulfur.

(e) The requirements of paragraph (b) of this section 

remain in force until and unless the EPA, in delegating 

enforcement authority to a state under section 111(c) of 

the Act, approves reporting requirements or an alternative 

means of compliance surveillance adopted by such state. In 

that event, affected sources within the state will be 

relieved of obligation to comply with paragraph (b) of this 

section, provided that they comply with the requirements 

established by the state.

§60.5425 What part of the General Provisions apply to me?

Table 3 to this subpart shows which parts of the 

General Provisions in §§60.1 through 60.19 apply to you.

§60.5430 What definitions apply to this subpart?

As used in this subpart, all terms not defined herein 

shall have the meaning given them in the Act, in subpart A 

or subpart VVa of part 60; and the following terms shall 

have the specific meanings given them.

Acid gas means a gas stream of hydrogen sulfide (H2S) 

and carbon dioxide (CO2) that has been separated from sour 

natural gas by a sweetening unit.

Alaskan North Slope means the approximately 69,000 
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square-mile area extending from the Brooks Range to the 

Arctic Ocean.

API Gravity means the weight per unit volume of 

hydrocarbon liquids as measured by a system recommended by 

the American Petroleum Institute (API) and is expressed in 

degrees.

Centrifugal Compressor means a piece of equipment that 

compresses a process gas by means of mechanical rotating 

vanes or impellers.

City gate means the delivery point at which natural 

gas is transferred from a transmission pipeline to the 

local gas utility.

Completion combustion device means any ignition 

device, installed horizontally or vertically, used in 

exploration and production operations to combust otherwise 

vented emissions from completions or workovers.

Compressor means a piece of equipment that compresses 

process gas and is usually a centrifugal compressor or a 

reciprocating compressor.

Compressor station means any permanent combination of 

compressors that move natural gas at increased pressure 

from fields, in transmission pipelines, or into storage.
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Condensate means a hydrocarbon liquid separated from 

natural gas that condenses due to changes in the 

temperature, pressure, or both, and remains liquid at 

standard conditions, as specified in §60.2. For the 

purposes of this subpart, a hydrocarbon liquid with an API 

gravity equal to or greater than 40 degrees is considered 

condensate.

Crude oil means crude petroleum oil any other 

hydrocarbon liquid, which are produced at the well in 

liquid form by ordinary production methods, and which are 

not the result of condensation of gas before or after it

leaves the reservoir. For the purposes of this subpart, a 

hydrocarbon liquid with an API gravity less than 40 degrees 

is considered crude oil.

Delineation well means a well drilled in order to 

determine the boundary of a field or producing reservoir.

Dehydrator means a device in which an absorbent 

directly contacts a natural gas stream and absorbs water in 

a contact tower or absorption column (absorber).

Equipment means each pump, pressure relief device, 

open-ended valve or line, valve, compressor, and flange or 

other connector that is in VOC service or in wet gas 
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service, and any device or system required by this subpart.

Field gas means feedstock gas entering the natural gas 

processing plant.

Field Gas Gathering means the system used transport 

field gas from a field to the main pipeline in the area.

Flare means a thermal oxidation system using an open 

(without enclosure) flame.

Flowback means the process of allowing fluids to flow 

from the well following a treatment, either in preparation 

for a subsequent phase of treatment or in preparation for 

cleanup and returning the well to production.

Flow line means surface pipe through which oil and/or 

natural gas travels from the well.

Gas-driven pneumatic controller means a pneumatic 

controller powered by pressurized natural gas.

Gas processing plant process unit means equipment 

assembled for the extraction of natural gas liquids from 

field gas, the fractionation of the liquids into natural 

gas products, or other operations associated with the 

processing of natural gas products. A process unit can 

operate independently if supplied with sufficient feed or 

raw materials and sufficient storage facilities for the 
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products.

Gas well means a well, the principal production of 

which at the mouth of the well is gas.

High-Bleed Pneumatic Devices means automated, 

continuous bleed flow control devices powered by 

pressurized natural gas and used for maintaining a process 

condition such as liquid level, pressure, delta-pressure 

and temperature. Part of the gas power stream which is 

regulated by the process condition flows to a valve 

actuator controller where it vents continuously (bleeds) to 

the atmosphere at a rate in excess of six standard cubic 

feet per hour. 

Hydraulic fracturing means process of directing 

pressurized liquids, containing water, proppant, and any 

added chemicals, to penetrate tight sand, shale, or coal 

formations that involve high rate, extended back flow to 

expel fracture fluids and sand during completions and well 

workovers. 

In light liquid service means that the piece of 

equipment contains a liquid that meets the conditions 

specified in §60.485a(e) or §60.5401(h)(2) of this part.

In wet gas service means that a compressor or piece of 
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equipment contains or contacts the field gas before the 

extraction step at a gas processing plant process unit.

Liquefied natural gas unit means a unit used to cool 

natural gas to the point at which it is condensed into a 

liquid which is colorless, odorless, non-corrosive and nontoxic. 

Low-bleed pneumatic controller means automated flow 

control devices powered by pressurized natural gas and used 

for maintaining a process condition such as liquid level, 

pressure, delta-pressure and temperature. Part of the gas 

power stream which is regulated by the process condition 

flows to a valve actuator controller where it vents 

continuously (bleeds) to the atmosphere at a rate equal to 

or less than six standard cubic feet per hour.

Modification means any physical change in, or change 

in the method of operation of, an affected facility which 

increases the amount of VOC or natural gas emitted into the 

atmosphere by that facility or which results in the 

emission of VOC or natural gas into the atmosphere not 

previously emitted. For the purposes of this subpart, each 

recompletion of a fractured or refractured existing gas 

well is considered to be a modification.
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Natural gas liquids means the hydrocarbons, such as 

ethane, propane, butane, and pentane that are extracted 

from field gas.

Natural gas processing plant (gas plant) means any 

processing site engaged in the extraction of natural gas 

liquids from field gas, fractionation of mixed natural gas 

liquids to natural gas products, or both.

Nonfractionating plant means any gas plant that does 

not fractionate mixed natural gas liquids into natural gas 

products.

Non gas-driven pneumatic device means an instrument 

that is actuated using other sources of power than 

pressurized natural gas; examples include solar, electric, 

and instrument air.

Onshore means all facilities except those that are 

located in the territorial seas or on the outer continental 

shelf.

Plunger lift system means an intermittent gas lift 

that uses gas pressure buildup in the casing-tubing annulus 

to push a steel plunger, and the column of fluid ahead of 

it, up the well tubing to the surface.

Pneumatic controller means an automated instrument 
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used for maintaining a process condition such as liquid 

level, pressure, delta-pressure and temperature.

Pneumatic pump means a pump that uses pressurized 

natural gas to move a piston or diaphragm, which pumps 

liquids on the opposite side of the piston or diaphragm.

Process unit means components assembled for the 

extraction of natural gas liquids from field gas, the 

fractionation of the liquids into natural gas products, or 

other operations associated with the processing of natural 

gas products. A process unit can operate independently if 

supplied with sufficient feed or raw materials and 

sufficient storage facilities for the products.

Reciprocating compressor means a piece of equipment 

that increases the pressure of a process gas by positive 

displacement, employing linear movement of the driveshaft.

Reciprocating compressor rod packing means a series of 

flexible rings in machined metal cups that fit around the 

reciprocating compressor piston rod to create a seal 

limiting the amount of compressed natural gas that escapes 

to the atmosphere.

Reduced emissions completion means a well completion 

where gas flowback that is otherwise vented is captured, 
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cleaned, and routed to the sales line.

Reduced emissions recompletion means a well completion 

following refracturing of a gas well where gas flowback 

that is otherwise vented is captured, cleaned, and routed 

to the sales line.

Reduced sulfur compounds means H2S, carbonyl sulfide 

(COS), and carbon disulfide (CS2).

Routed to a process or route to a process means the 

emissions are conveyed to any enclosed portion of a process 

unit where the emissions are predominantly recycled and/or 

consumed in the same manner as a material that fulfills the 

same function in the process and/or transformed by chemical 

reaction into materials that are not regulated materials 

and/or incorporated into a product; and/or recovered.

Sales line means pipeline, generally small in 

diameter, used to transport oil or gas from the well to a 

processing facility or a mainline pipeline.

Salable quality gas means natural gas that meets the 

composition, moisture, or other limits set by the purchaser 

of the natural gas.

Storage vessel means a stationary vessel or series of 

stationary vessels that are either manifolded together or 
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are located at a single well site and that have potential 

for VOC emissions equal to or greater than 10 tpy.

Sulfur production rate means the rate of liquid sulfur 

accumulation from the sulfur recovery unit.

Sulfur recovery unit means a process device that 

recovers element sulfur from acid gas.

Sweetening unit means a process device that removes 

hydrogen sulfide and/or carbon dioxide from the natural gas 

stream. 

Surface site means any combination of one or more 

graded pad sites, gravel pad sites, foundations, platforms, 

or the immediate physical location upon which equipment is 

physically affixed.

Total SO2 equivalents means the sum of volumetric or 

mass concentrations of the sulfur compounds obtained by 

adding the quantity existing as SO2 to the quantity of SO2

that would be obtained if all reduced sulfur compounds were 

converted to SO2 (ppmv or kg/dscm (lb/dscf)).

Total Reduced Sulfur (TRS) means the sum of the sulfur 

compounds hydrogen sulfide, methyl mercaptan, dimethyl 

sulfide, and dimethyl disulfide as measured by Method 16 of 

appendix A to part 60 of this chapter.
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Underground storage tank means a storage tank stored 

below ground.

Well means an oil or gas well, a hole drilled for the 

purpose of producing oil or gas, or a well into which 

fluids are injected.

Well completion means the process that allows for the 

flow of petroleum or natural gas from newly drilled wells 

to expel drilling and reservoir fluids and tests the 

reservoir flow characteristics, steps which may vent 

produced gas to the atmosphere via an open pit or tank. 

Well completion also involves connecting the well bore to 

the reservoir, which may include treating the formation or 

installing tubing, packer(s), or lifting equipment.

Well completion operation means any well completion or 

well workover occurring at a gas wellhead affected 

facility.

Well site means the areas that are directly disturbed 

during the drilling and subsequent operation of, or 

affected by, production facilities directly associated with 

any oil well, gas well, or injection well and its 

associated well pad.

Wellhead means the piping, casing, tubing and 
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connected valves protruding above the earth’s surface for 

an oil and/or natural gas well. The wellhead ends where the 

flow line connects to a wellhead valve. The wellhead does 

not include other equipment at the well site except for any 

conveyance through which gas is vented to the atmosphere.

Wildcat well means a well outside known fields or the 

first well drilled in an oil or gas field where no other 

oil and gas production exists. 

Table 1. Required Minimum Initial SO2 Emission Reduction 

Efficiency (Zi)

H2S 

content of 

acid gas 

(Y), %

Sulfur feed rate (X), LT/D

2.0<X<5.0 5.0<X<15.0 15.0<X<300.0 X>300.0

Y>50 79.0 ............88.51X0.0101Y

0.0125 .............

or 99.9, whichever is smaller

20<Y<50 79.0 .......... 88.5X0.0101Y

0.0125 ..........

or 97.9, whichever is smaller

97.9

10<Y<20 79.0 88.5X0.0101Y

0.0125

or 97.9, whichever 

is smaller

93.5 93.5

Y<10 79.0 79.0 79.0 79.0

Table 2. Required Minimum SO2 Emission Reduction Efficiency 

(Zc)

H2S 

content of 

acid gas 

(Y), %

Sulfur feed rate (X), LT/D

2.0<X<5.0 5.0<X<15.0 15.0<X<300.0 X>300.0

Y>50 74.0 ............85.35X0.0144Y

0.0128 .............

or 99.9, whichever is smaller

20<Y<50 74.0 .......... 85.35X0.0144Y

0.0128 ......... 97.5
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or 97.9, whichever is smaller

10<Y<20 74.0 85.35X0.0144Y

0.0128

or 90.8, whichever 

is smaller

90.8 90.8

Y<10 74.0 74.0 74.0 74.0

E = The sulfur emission rate expressed as elemental sulfur, 

kilograms per hour (kg/hr) [pounds per hour (lb/hr)], 

rounded to one decimal place.

R = The sulfur emission reduction efficiency achieved in 

percent, carried to one decimal place.

S = The sulfur production rate, kilograms per hour (kg/hr) 

[pounds per hour (lb/hr)], rounded to one decimal place.

X = The sulfur feed rate from the sweetening unit (i.e., 

the H2S in the acid gas), expressed as sulfur, Mg/D(LT/D), 

rounded to one decimal place.

Y = The sulfur content of the acid gas from the sweetening 

unit, expressed as mole percent H2S (dry basis) rounded to 

one decimal place.

Z = The minimum required sulfur dioxide (SO2) emission 

reduction efficiency, expressed as percent carried to one 

decimal place. Zi refers to the reduction efficiency 

required at the initial performance test. Zc refers to the 

reduction efficiency required on a continuous basis after 

compliance with Zi has been demonstrated.

Table 3 to Subpart OOOO of part 60 – Applicability of 

General Provisions to Subpart OOOO

As stated in §60.5425, you must comply with the following 

applicable General Provisions:

General 

Provisions 

Citation

Subject of 

Citation

Applies 

to 

subpart? Explanation

§60.1

General 

applicability of 

the General 

Provisions

Yes

§60.2 Definitions Yes Additional terms 

defined in 

§60.5430
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§60.3 Units and 

abbreviations

Yes

§60.4 Address Yes

§60.5 Determination of 

construction or 

modification

Yes

§60.6 Review of plans Yes

§60.7 Notification and 

record keeping

Yes Except that §60.7 

only applies as 

specified in 

§60.5420(a).

§60.8 Performance tests No Performance 

testing is 

required for 

storage vessels 

as specified in 

40 CFR part 63, 

subpart HH.

§60.9 Availability of 

information

Yes

§60.10 State authority Yes 

§60.11 Compliance with 

standards and 

maintenance 

requirements

No Requirements are 

specified in 

subpart OOOO.

§60.12 Circumvention Yes

§60.13 Monitoring 

requirements

Yes Continuous 

monitors are 

required for 

storage vessels

§60.14 Modification Yes

§60.15 Reconstruction Yes

§60.16 Priority list Yes

§60.17 Incorporations by 

reference

Yes

§60.18 General control 

device 

requirements

Yes

§60.19 General 

notification and 

reporting 

requirement

Yes

PART 63--[AMENDED]
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8. The authority citation for part 63 continues to 

read as follows:

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

9. Section 63.14 is amended by:

a. Adding paragraphs (b)(67), (b)(68), (b)(69) and 

(b)(70); and

b. Revising paragraph (i)(1) to read as follows:

§63.14 Incorporations by reference.

* * * * *

(b) * * *

* * * * *

(67) ASTM D1945 – 03(2010) Standard Test Method for 

Analysis of Natural Gas by Gas Chromatography, IBR approved 

for §§63.772 and 63.1282. 

(68) ASTM D5504 - 08 Standard Test Method for 

Determination of Sulfur Compounds in Natural Gas and 

Gaseous Fuels by Gas Chromatography and Chemiluminescence , 

IBR approved for §§63.772 and 63.1282.

(69) ASTM D3588 - 98(2003) Standard Practice for 

Calculating Heat Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels, IBR approved for 

§§63.772 and 63.1282.
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(70) ASTM D4891 - 89(2006) Standard Test Method for 

Heating Value of Gases in Natural Gas Range by 

Stoichiometric Combustion, IBR approved for §§63.772 and 

63.1282.

* * * * *

(i) * * *

(1) ANSI/ASME PTC 19.10–1981, Flue and Exhaust Gas 

Analyses [Part 10, Instruments and Apparatus], issued 

August 31, 1981 IBR approved for §§63.309(k)(1)(iii),

63.771(e), 63.865(b), 63.1281(d), 63.3166(a)(3), 

63.3360(e)(1)(iii), 63.3545(a)(3), 63.3555(a)(3), 

63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3), 63.4965(a)(3), 

63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), 

63.11148(e)(3)(iii), 63.11155(e)(3), 63.11162(f)(3)(iii) 

and (f)(4), 63.11163(g)(1)(iii) and (g)(2), 

63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), 

63.11646(a)(1)(iii), table 5 to subpart DDDDD of this part, 

and table 1 to subpart ZZZZZ of this part.

* * * * *

Subpart HH-–[AMENDED]

10. Section 63.760 is amended by:

a. Revising paragraph (a)(1) introductory text;
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b. Revising paragraph (a)(1)(iii);

c. Revising paragraph (a)(2); 

d. Revising paragraph (b)(1)(ii);

e. Revising paragraph (f) introductory text;

f. Revising paragraph (f)(1);

g. Revising paragraph (f)(2); and

h. Adding paragraphs (f)(7), (f)(8), (f)(9) and 

(f)(10) to read as follows:

§63.760 Applicability and designation of affected source.

(a) * * *

(1) Facilities that are major or area sources of 

hazardous air pollutants (HAP) as defined in §63.761. 

Emissions for major source determination purposes can be 

estimated using the maximum natural gas or hydrocarbon 

liquid throughput, as appropriate, calculated in paragraphs 

(a)(1)(i) through (iii) of this section. As an alternative 

to calculating the maximum natural gas or hydrocarbon 

liquid throughput, the owner or operator of a new or 

existing source may use the facility's design maximum 

natural gas or hydrocarbon liquid throughput to estimate 

the maximum potential emissions. Other means to determine 

the facility's major source status are allowed, provided 
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the information is documented and recorded to the 

Administrator's satisfaction in accordance with 

§63.10(b)(3). A facility that is determined to be an area 

source, but subsequently increases its emissions or its 

potential to emit above the major source levels, and 

becomes a major source, must comply thereafter with all 

provisions of this subpart applicable to a major source 

starting on the applicable compliance date specified in 

paragraph (f) of this section. Nothing in this paragraph is 

intended to preclude a source from limiting its potential 

to emit through other appropriate mechanisms that may be 

available through the permitting authority.

* * * * *

(iii) The owner or operator shall determine the 

maximum values for other parameters used to calculate 

emissions as the maximum for the period over which the 

maximum natural gas or hydrocarbon liquid throughput is 

determined in accordance with paragraph (a)(1)(i)(A) or (B) 

of this section. Parameters, other than glycol circulation 

rate, shall be based on either highest measured values or 

annual average. For estimating maximum potential emissions 

from glycol dehydration units, the glycol circulation rate 
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used in the calculation shall be the unit’s maximum rate 

under its physical and operational design consistent with 

the definition of potential to emit in §63.2.

(2) Facilities that process, upgrade, or store 

hydrocarbon liquids prior to the point where hydrocarbon 

liquids enter either the Organic Liquids Distribution (Nongasoline) or Petroleum Refineries source categories.

* * * * *

(b) * * *

(1) * * *

* * * * *

(ii) Each storage vessel;

* * * * *

(f) The owner or operator of an affected major source 

shall achieve compliance with the provisions of this 

subpart by the dates specified in paragraphs (f)(1), 

(f)(2), and (f)(7) through (f)(10) of this section. The 

owner or operator of an affected area source shall achieve 

compliance with the provisions of this subpart by the dates 

specified in paragraphs (f)(3) through (f)(6) of this 

section.
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(1) Except as specified in paragraphs (f)(7) through

(10) of this section, the owner or operator of an affected 

major source, the construction or reconstruction of which 

commenced before February 6, 1998, shall achieve compliance 

with the applicable provisions of this subpart no later 

than June 17, 2002, except as provided for in §63.6(i). The 

owner or operator of an area source, the construction or 

reconstruction of which commenced before February 6, 1998, 

that increases its emissions of (or its potential to emit) 

HAP such that the source becomes a major source that is 

subject to this subpart shall comply with this subpart 3 

years after becoming a major source.

(2) Except as specified in paragraphs (f)(7) through 

(10) of this section, the owner or operator of an affected 

major source, the construction or reconstruction of which 

commences on or after February 6, 1998, shall achieve 

compliance with the applicable provisions of this subpart 

immediately upon initial startup or June 17, 1999, 

whichever date is later. Area sources, other than 

production field facilities identified in (f)(9) of this 

section, the construction or reconstruction of which 

commences on or after February 6, 1998, that become major 
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sources shall comply with the provisions of this standard 

immediately upon becoming a major source.

* * * * *

(7) Each affected small glycol dehydration unit and 

each storage vessel that is not a storage vessel with the 

potential for flash emissions located at a major source,

that commenced construction before [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER] must achieve 

compliance no later than 3 years after the date of 

publication of the final rule in the Federal Register, 

except as provided in §63.6(i).

(8) Each affected small glycol dehydration unit and 

each storage vessel that is not a storage vessel with the 

potential for flash emissions, both as defined in §63.761, 

located at a major source, that commenced construction on 

or after [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER] must achieve compliance immediately upon initial 

startup or the date of publication of the final rule in the 

Federal Register, whichever is later.

(9) A production field facility, as defined in 

§63.761, constructed before [INSERT DATE OF PUBLICATION IN 

THE FEDERAL REGISTER] that was previously determined to be 
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an area source but becomes a major source (as defined in 

paragraph 3 of the major source definition in §63.761) on 

the date of publication of the final rule in the Federal 

Register must achieve compliance no later than 3 years 

after the date of publication of the final rule in the 

Federal Register, except as provided in §63.6(i).

(10) Each large glycol dehydration unit, as defined in 

§63.761, that has complied with the provisions of this 

subpart prior to [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER] by reducing its benzene emissions to less than 

0.9 megagrams per year must achieve compliance no later 

than 90 days after the date of publication of the final 

rule in the Federal Register, except as provided in 

§63.6(i).

* * * * *

11. Section 63.761 is amended by:

a. Adding, in alphabetical order, new definitions for

the terms “affirmative defense,” “BTEX,” “flare,” “large 

glycol dehydration units” and “small glycol dehydration 

units”;

b. Revising the definition for “associated equipment,”
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“facility,” “glycol dehydration unit baseline operations,” 

and “temperature monitoring device”; and

c. Revising paragraph (3) of the definition for “major 

source” to read as follows:

§63.761 Definitions.

* * * * *

Affirmative defense means, in the context of an 

enforcement proceeding, a response or defense put forward 

by a defendant, regarding which the defendant has the 

burden of proof, and the merits of which are independently 

and objectively evaluated in a judicial or administrative 

proceeding.

* * * * *

Associated equipment, as used in this subpart and as 

referred to in section 112(n)(4) of the Act, means 

equipment associated with an oil or natural gas exploration 

or production well, and includes all equipment from the 

wellbore to the point of custody transfer, except glycol 

dehydration units and storage vessels.

* * * * *

BTEX means benzene, toluene, ethyl benzene and xylene.

* * * * *
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Facility means any grouping of equipment where 

hydrocarbon liquids are processed, upgraded (i.e., remove 

impurities or other constituents to meet contract 

specifications), or stored; or where natural gas is 

processed, upgraded, or stored. For the purpose of a major 

source determination, facility (including a building, 

structure, or installation) means oil and natural gas 

production and processing equipment that is located within 

the boundaries of an individual surface site as defined in 

this section. Equipment that is part of a facility will 

typically be located within close proximity to other 

equipment located at the same facility. Pieces of 

production equipment or groupings of equipment located on 

different oil and gas leases, mineral fee tracts, lease 

tracts, subsurface or surface unit areas, surface fee 

tracts, surface lease tracts, or separate surface sites, 

whether or not connected by a road, waterway, power line or 

pipeline, shall not be considered part of the same 

facility. Examples of facilities in the oil and natural gas 

production source category include, but are not limited to, 

well sites, satellite tank batteries, central tank 

batteries, a compressor station that transports natural gas 
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to a natural gas processing plant, and natural gas 

processing plants.

* * * * *

Flare means a thermal oxidation system using an open 

flame (i.e., without enclosure).

* * * * *

Glycol dehydration unit baseline operations means 

operations representative of the large glycol dehydration 

unit operations as of June 17, 1999 and the small glycol 

dehydrator unit operations as of [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. For the purposes of 

this subpart, for determining the percentage of overall HAP 

emission reduction attributable to process modifications, 

baseline operations shall be parameter values (including, 

but not limited to, glycol circulation rate or glycol-HAP 

absorbency) that represent actual long-term conditions 

(i.e., at least 1 year). Glycol dehydration units in 

operation for less than 1 year shall document that the 

parameter values represent expected long-term operating 

conditions had process modifications not been made.

* * * * *
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Large glycol dehydration unit means a glycol 

dehydration unit with an actual annual average natural gas 

flowrate equal to or greater than 85 thousand standard 

cubic meters per day and actual annual average benzene 

emissions equal to or greater than 0.90 Mg/yr, determined 

according to §63.772(b).

* * * * *

Major source * * * 

(3) For facilities that are production field 

facilities, only HAP emissions from glycol dehydration 

units and storage vessels shall be aggregated for a major 

source determination. For facilities that are not 

production field facilities, HAP emissions from all HAP 

emission units shall be aggregated for a major source 

determination.

* * * * *

Small glycol dehydration unit means a glycol 

dehydration unit, located at a major source, with an actual 

annual average natural gas flowrate less than 85 thousand 

standard cubic meters per day or actual annual average 

benzene emissions less than 0.90 Mg/yr, determined 

according to §63.772(b).
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* * * * *

Temperature monitoring device means an instrument used 

to monitor temperature and having a minimum accuracy of ±1

percent of the temperature being monitored expressed in °C, 

or ±2.5 °C, whichever is greater. The temperature 

monitoring device may measure temperature in degrees 

Fahrenheit or degrees Celsius, or both.

12. Section 63.762 is amended by:

a. Revising paragraphs (a) through (d); and

b. Removing paragraph (e) to read as follows:

§63.762 Startups and shutdowns.

(a) The provisions set forth in this subpart shall 

apply at all times.

(b) The owner or operator shall not shut down items of 

equipment that are required or utilized for compliance with 

the provisions of this subpart during times when emissions 

are being routed to such items of equipment, if the 

shutdown would contravene requirements of this subpart 

applicable to such items of equipment. This paragraph does 

not apply if the owner or operator must shut down the 

equipment to avoid damage due to a contemporaneous startup 

or shutdown, of the affected source or a portion thereof.
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(c) During startups and shutdowns, the owner or 

operator shall implement measures to prevent or minimize 

excess emissions to the maximum extent practical. 

(d) In response to an action to enforce the standards 

set forth in this subpart, you may assert an affirmative

defense to a claim for civil penalties for exceedances of 

such standards that are caused by malfunction, as defined 

in 40 CFR 63.2. Appropriate penalties may be assessed, 

however, if you fail to meet your burden of proving all the 

requirements in the affirmative defense. The affirmative 

defense shall not be available for claims for injunctive 

relief.

(1) To establish the affirmative defense in any action 

to enforce such a limit, you must timely meet the 

notification requirements in paragraph (d)(2) of this 

section, and must prove by a preponderance of evidence 

that:

(i) The excess emissions:

(A) Were caused by a sudden, infrequent, and 

unavoidable failure of air pollution control and monitoring 

equipment, process equipment, or a process to operate in a 

normal or usual manner; and 
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(B) Could not have been prevented through careful 

planning, proper design or better operation and maintenance 

practices; and

(C) Did not stem from any activity or event that could 

have been foreseen and avoided, or planned for; and 

(D) Were not part of a recurring pattern indicative of 

inadequate design, operation, or maintenance; and 

(ii) Repairs were made as expeditiously as possible 

when the applicable emission limitations were being 

exceeded. Off-shift and overtime labor were used, to the 

extent practicable to make these repairs; and 

(iii) The frequency, amount and duration of the excess 

emissions (including any bypass) were minimized to the 

maximum extent practicable during periods of such 

emissions; and 

(iv) If the excess emissions resulted from a bypass of 

control equipment or a process, then the bypass was 

unavoidable to prevent loss of life, personal injury, or 

severe property damage; and 

(v) All possible steps were taken to minimize the 

impact of the excess emissions on ambient air quality, the 

environment, and human health; and 
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(vi) All emissions monitoring and control systems were 

kept in operation if at all possible, consistent with 

safety and good air pollution control practices; and 

(vii) All of the actions in response to the excess 

emissions were documented by properly signed, 

contemporaneous operating logs; and 

(viii) At all times, the affected source was operated 

in a manner consistent with good practices for minimizing 

emissions; and 

(ix) A written root cause analysis has been prepared 

to determine, correct, and eliminate the primary causes of 

the malfunction and the excess emissions resulting from the 

malfunction event at issue. The analysis shall also 

specify, using best monitoring methods and engineering 

judgment, the amount of excess emissions that were the 

result of the malfunction.

(2) Notification. The owner or operator of the 

affected source experiencing exceedance of its emission 

limit(s) during a malfunction shall notify the 

Administrator by telephone or facsimile transmission as 

soon as possible, but no later than two business days after 

the initial occurrence of the malfunction, if it wishes to 
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avail itself of an affirmative defense to civil penalties 

for that malfunction. The owner or operator seeking to 

assert an affirmative defense shall also submit a written 

report to the Administrator within 45 days of the initial 

occurrence of the exceedance of the standard in this 

subpart to demonstrate, with all necessary supporting 

documentation, that it has met the requirements set forth 

in paragraph (d)(1) of this section. The owner or operator 

may seek an extension of this deadline for up to 30 

additional days by submitting a written request to the 

Administrator before the expiration of the 45 day period. 

Until a request for an extension has been approved by the 

Administrator, the owner or operator is subject to the 

requirement to submit such report within 45 days of the 

initial occurrence of the exceedance. 

* * * * *

13. Section 63.764 is amended by:

a. Revising paragraph (c)(2) introductory text;

b. Revising paragraph (e) introductory text; and 

c. Revising paragraph (i) introductory text; and

d. Adding paragraph (j) to read as follows:

§63.764 General standards.
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* * * * *

(c) * * *

* * * * *

(2) For each storage vessel subject to this subpart, 

the owner or operator shall comply with the requirements 

specified in paragraphs (c)(2)(i) through (iii) of this 

section.

* * * * *

(e) Exemptions. (1) The owner or operator of an area 

source is exempt from the requirements of paragraph (d) of 

this section if the criteria listed in paragraph (e)(1)(i) 

or (ii) of this section are met, except that the records of 

the determination of these criteria must be maintained as 

required in §63.774(d)(1).

* * * * *

(i) In all cases where the provisions of this subpart 

require an owner or operator to repair leaks by a specified 

time after the leak is detected, it is a violation of this 

standard to fail to take action to repair the leak(s) 

within the specified time. If action is taken to repair the 

leak(s) within the specified time, failure of that action 

to successfully repair the leak(s) is not a violation of 
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this standard. However, if the repairs are unsuccessful, 

and a leak is detected, the owner or operator shall take 

further action as required by the applicable provisions of 

this subpart.

(j) At all times the owner or operator must operate 

and maintain any affected source, including associated air 

pollution control equipment and monitoring equipment, in a 

manner consistent with safety and good air pollution 

control practices for minimizing emissions. Determination 

of whether such operation and maintenance procedures are 

being used will be based on information available to the 

Administrator which may include, but is not limited to, 

monitoring results, review of operation and maintenance 

procedures, review of operation and maintenance records, 

and inspection of the source.

* * * * *

14. Section 63.765 is amended by:

a. Revising paragraph (a);

b. Revising paragraph (b)(1) introductory text;

c. Revising paragraphs (b)(1)(i) and (ii);

d. Adding paragraph (b)(1)(iii);

e. Revising paragraph (c)(2);
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f. Revising paragraph (c)(3) introductory text;

g. Revising paragraphs (c)(3)(i) and (ii); and

h. Adding paragraph (c)(3)(iii) to read as follows:

§63.765 Glycol dehydration unit process vent standards.

(a) This section applies to each glycol dehydration 

unit subject to this subpart that must be controlled for 

air emissions as specified in either paragraph (c)(1)(i) or 

paragraph (d)(1)(i) of §63.764.

(b) * * *

(1) For each glycol dehydration unit process vent, the 

owner or operator shall control air emissions by either 

paragraph (b)(1)(i), (ii), or (iii) of this section.

(i) The owner or operator of a large glycol 

dehydration unit, as defined in §63.761, shall connect the 

process vent to a control device or a combination of 

control devices through a closed-vent system. The closedvent system shall be designed and operated in accordance 

with the requirements of §63.771(c). The control device(s) 

shall be designed and operated in accordance with the 

requirements of §63.771(d).

(ii) The owner or operator of a glycol dehydration 

unit located at an area source, that must be controlled as 
*** E.O. 12866 Review 

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specified in §63.764(d)(1)(i), shall 

vent to a control device or combination of control devices 

through a closed-vent system and the outlet benzene 

emissions from the control device(s) shall be reduced to a 

level less than 0.90 megagrams per year

system shall be designed and operated in accordance with 

the requirements of §63.771(c)

be designed and operated in accordance with the 

requirements of §63.771(d), except that the performance 

levels specified in §63.771(d)(1)(i) and (ii

(iii) You must limit BTEX emissions from each small 

glycol dehydration unit process vent, as defined in 

§63.761, to the limit determined in Equation 1 of this 

section. The limit must be met in accordance with one of 

the alternatives specif

through (D) of this section.

Equation 1

Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per 

year;

1.10x10-4 = BTEX emission limit, grams BTEX/standard cubic 

meter -ppmv;

Throughput = Annual ave

standard cubic meters per day

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Page 439 of 601

specified in §63.764(d)(1)(i), shall connect the process 

vent to a control device or combination of control devices 

vent system and the outlet benzene 

emissions from the control device(s) shall be reduced to a 

level less than 0.90 megagrams per year. The closedall be designed and operated in accordance with 

the requirements of §63.771(c). The control device(s) shall 

be designed and operated in accordance with the 

requirements of §63.771(d), except that the performance 

levels specified in §63.771(d)(1)(i) and (ii) do not apply.

(iii) You must limit BTEX emissions from each small 

glycol dehydration unit process vent, as defined in 

§63.761, to the limit determined in Equation 1 of this 

The limit must be met in accordance with one of 

the alternatives specified in paragraphs (b)(1)(iii)(A) 

through (D) of this section.

 

specific BTEX emission limit, megagrams per 

= BTEX emission limit, grams BTEX/standard cubic 

Throughput = Annual average daily natural gas throughput, 

standard cubic meters per day;

Do Not Cite, 

connect the process 

vent to a control device or combination of control devices 

vent system and the outlet benzene 

emissions from the control device(s) shall be reduced to a 

-vent 

all be designed and operated in accordance with 

The control device(s) shall 

requirements of §63.771(d), except that the performance 

) do not apply.

(iii) You must limit BTEX emissions from each small 

glycol dehydration unit process vent, as defined in 

§63.761, to the limit determined in Equation 1 of this 

The limit must be met in accordance with one of 

ied in paragraphs (b)(1)(iii)(A) 

 

specific BTEX emission limit, megagrams per 

= BTEX emission limit, grams BTEX/standard cubic 

rage daily natural gas throughput, 
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Page 440 of 601

Ci,BTEX = BTEX concentration of the natural gas at the inlet 

to the glycol dehydration unit, ppmv.

(A) Connect the process vent to a control device or 

combination of control devices through a closed-vent 

system. The closed vent system shall be designed and 

operated in accordance with the requirements of §63.771(c). 

The control device(s) shall be designed and operated in 

accordance with the requirements of §63.771(f).

(B) Meet the emissions limit through process 

modifications in accordance with the requirements specified 

in §63.771(e).

(C) Meet the emissions limit for each small glycol 

dehydration unit using a combination of process 

modifications and one or more control devices through the 

requirements specified in paragraphs (b)(1)(iii)(A) and (B) 

of this section.

(D) Demonstrate that the emissions limit is met 

through actual uncontrolled operation of the small glycol 

dehydration unit. Document operational parameters in 

accordance with the requirements specified in §63.771(e) 

and emissions in accordance with the requirements specified 

in §63.772(b)(2).

* * * * *
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(c) * * *

* * * * *

(2) The owner or operator shall demonstrate, to the 

Administrator's satisfaction, that the total HAP emissions 

to the atmosphere from the large glycol dehydration unit 

process vent are reduced by 95.0 percent through process 

modifications, or a combination of process modifications 

and one or more control devices, in accordance with the 

requirements specified in §63.771(e).

(3) Control of HAP emissions from a GCG separator 

(flash tank) vent is not required if the owner or operator 

demonstrates, to the Administrator's satisfaction, that 

total emissions to the atmosphere from the glycol 

dehydration unit process vent are reduced by one of the 

levels specified in paragraph (c)(3)(i), (ii), or (iii) of 

this section, through the installation and operation of 

controls as specified in paragraph (b)(1) of this section.

(i) For any large glycol dehydration unit, HAP 

emissions are reduced by 95.0 percent or more.

(ii) For area source dehydration units, benzene 

emissions are reduced to a level less than 0.90 megagrams 

per year.
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(iii) For each small glycol dehydration unit, BTEX 

emissions are reduced to a level less than the limit 

calculated by paragraph (b)(1)(iii) of this section.

15. Section 63.766 is amended by:

a. Revising paragraph (a);

b. Revising paragraph (b) introductory text;

c. Revising paragraph (b)(1); and

d. Revising paragraph (d) to read as follows:

§63.766 Storage vessel standards.

(a) This section applies to each storage vessel (as 

defined in §63.761) subject to this subpart.

(b) The owner or operator of a storage vessel (as 

defined in §63.761) shall comply with one of the control 

requirements specified in paragraphs (b)(1) and (2) of this 

section.

(1) The owner or operator shall equip the affected 

storage vessel with a cover that is connected, through a 

closed-vent system that meets the conditions specified in 

§63.771(c), to a control device or a combination of control 

devices that meets any of the conditions specified in 

§63.771(d). The cover shall be designed and operated in 

accordance with the requirements of §63.771(b).
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* * * * *

(d) This section does not apply to storage vessels for 

which the owner or operator is subject to and controlled 

under the requirements specified in 40 CFR part 60, subpart 

Kb; or the requirements specified under 40 CFR part 63 

subparts G or CC. 

* * * * *

16. Section 63.769 is amended by:

a. Revising paragraph (b); 

b. Revising paragraph (c); and

b. Revising paragraph (c)(8) to read as follows:

§63.769 Equipment leak standards.

* * * * *

(b) This section does not apply to ancillary equipment 

and compressors for which the owner or operator is subject 

to and controlled under the requirements specified in 

subpart H of this part; or the requirements specified in 40 

CFR part 60, subpart KKK.

(c) For each piece of ancillary equipment and each 

compressor subject to this section located at an existing 

or new source, the owner or operator shall meet the 

requirements specified in 40 CFR part 61, subpart V, 
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§§61.241 through 61.247, except as specified in paragraphs 

(c)(1) through (8) of this section, except for valves 

subject to §61.247-2(b) a leak is detected if an instrument 

reading of 500 ppm or greater is measured.

* * * * *

(8) Flares, as defined in §63.761, used to comply with 

this subpart shall comply with the requirements of 

§63.11(b).

* * * * *

17. Section 63.771 is amended by:

a. Revising paragraph (c)(1) introductory text;

b. Revising paragraph (d) introductory text;

c. Revising paragraph (d)(1)(i);

d. Revising paragraph (d)(1)(i)(C);

e. Revising paragraph (d)(1)(ii);

f. Revising paragraph (d)(1)(iii);

g. Revising paragraph (d)(4)(i);

h. Revising paragraph (d)(5)(i);

i. Revising paragraph (e)(2);

j. Revising paragraph (e)(3) introductory text;

k. Revising paragraph (e)(3)(ii); and

l. Adding paragraph (f) to read as follows:
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Page 445 of 601

§63.771 Control equipment requirements.

* * * * *

(c) Closed-vent system requirements. (1) The closedvent system shall route all gases, vapors, and fumes 

emitted from the material in an emissions unit to a control 

device that meets the requirements specified in paragraph 

(d) of this section.

* * * * *

(d) Control device requirements for sources except 

small glycol dehydration units. Owners and operators of 

small glycol dehydration units, shall comply with the 

control device requirements in paragraph (f) of this 

section. 

(1) * * *

(i) An enclosed combustion device (e.g., thermal vapor 

incinerator, catalytic vapor incinerator, boiler, or 

process heater) that is designed and operated in accordance 

with one of the following performance requirements:

* * * * *

(C) For a control device that can demonstrate a 

uniform combustion zone temperature during the performance 
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Page 446 of 601

test conducted under §63.772(e), operates at a minimum 

temperature of 760 degrees C.

* * * * *

(ii) A vapor recovery device (e.g., carbon adsorption 

system or condenser) or other non-destructive control device 

that is designed and operated to reduce the mass content of 

either TOC or total HAP in the gases vented to the device 

by 95.0 percent by weight or greater as determined in 

accordance with the requirements of §63.772(e).

(iii) A flare, as defined in §63.761, that is designed 

and operated in accordance with the requirements of 

§63.11(b).

* * * * *

(4) * * *

(i) Each control device used to comply with this 

subpart shall be operating at all times when gases, vapors, 

and fumes are vented from the HAP emissions unit or units 

through the closed-vent system to the control device, as 

required under §63.765, §63.766, and §63.769. An owner or 

operator may vent more than one unit to a control device 

used to comply with this subpart.

* * * * *
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(5) * * *

(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. Records identifying the 

schedule for replacement and records of each carbon 

replacement shall be maintained as required in 

§63.774(b)(7)(ix). The schedule for replacement shall be 

submitted with the Notification of Compliance Status Report 

as specified in §63.775(d)(5)(iv). Each carbon replacement 

must be reported in the Periodic Reports as specified in 

§63.772(e)(2)(xii).

* * * * *

(e) * * *

* * * * *

(2) The owner or operator shall document, to the 

Administrator's satisfaction, the conditions for which 

glycol dehydration unit baseline operations shall be 

modified to achieve the 95.0 percent overall HAP emission 

reduction, or BTEX limit determined in §63.765(b)(1)(iii), 

as applicable, either through process modifications or 
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Page 448 of 601

through a combination of process modifications and one or 

more control devices. If a combination of process 

modifications and one or more control devices are used, the 

owner or operator shall also establish the emission 

reduction to be achieved by the control device to achieve 

an overall HAP emission reduction of 95.0 percent for the 

glycol dehydration unit process vent or, if applicable, the 

BTEX limit determined in §63.765(b)(1)(iii) for the small 

glycol dehydration unit process vent. Only modifications in 

glycol dehydration unit operations directly related to 

process changes, including but not limited to changes in 

glycol circulation rate or glycol-HAP absorbency, shall be 

allowed. Changes in the inlet gas characteristics or 

natural gas throughput rate shall not be considered in 

determining the overall emission reduction due to process 

modifications.

(3) The owner or operator that achieves a 95.0 percent 

HAP emission reduction or meets the BTEX limit determined 

in §63.765(b)(1)(iii), as applicable, using process 

modifications alone shall comply with paragraph (e)(3)(i) 

of this section. The owner or operator that achieves a 95.0 

percent HAP emission reduction or meets the BTEX limit 
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Page 449 of 601

determined in §63.765(b)(1)(iii), as applicable, using a 

combination of process modifications and one or more 

control devices shall comply with paragraphs (e)(3)(i) and 

(e)(3)(ii) of this section.

* * * * *

(ii) The owner or operator shall comply with the 

control device requirements specified in paragraph (d) or 

(f) of this section, as applicable, except that the 

emission reduction or limit achieved shall be the emission 

reduction or limit specified for the control device(s) in 

paragraph (e)(2) of this section.

(f) Control device requirements for small glycol 

dehydration units.

(1) The control device used to meet BTEX the emission 

limit calculated in §63.765(b)(1)(iii) shall be one of the 

control devices specified in paragraphs (f)(1)(i) through 

(iii) of this section.

(i) An enclosed combustion device (e.g., thermal vapor 

incinerator, catalytic vapor incinerator, boiler, or 

process heater) that is designed and operated to reduce the 

mass content of BTEX in the gases vented to the device as 

determined in accordance with the requirements of 
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§63.772(e). If a boiler or process heater is used as the 

control device, then the vent stream shall be introduced 

into the flame zone of the boiler or process heater; or

(ii) A vapor recovery device (e.g., carbon adsorption 

system or condenser) or other non-destructive control device 

that is designed and operated to reduce the mass content of 

BTEX in the gases vented to the device as determined in 

accordance with the requirements of §63.772(e); or

(iii) A flare, as defined in §63.761, that is designed 

and operated in accordance with the requirements of 

§63.11(b). 

(2) The owner or operator shall operate each control 

device in accordance with the requirements specified in 

paragraphs (f)(2)(i) and (ii) of this section.

(i) Each control device used to comply with this 

subpart shall be operating at all times. An owner or 

operator may vent more than one unit to a control device 

used to comply with this subpart.

(ii) For each control device monitored in accordance 

with the requirements of §63.773(d), the owner or operator 

shall demonstrate compliance according to the requirements 

of either §63.772(f) or (h).
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(3) For each carbon adsorption system used as a 

control device to meet the requirements of paragraph 

(f)(1)(ii) of this section, the owner or operator shall 

manage the carbon as required under (d)(5)(i) and (ii) of 

this section.

18. Section 63.772 is amended by:

a. Revising paragraph (b) introductory text;

b. Revising paragraph (b)(1)(ii);

c. Revising paragraph (b)(2);

d. Revising paragraphs (b)(2)(i) through (ii);

e. Adding paragraph (d);

f. Revising paragraph (e) introductory text;

g. Revising paragraphs (e)(1)(i) through (v);

h. Revising paragraph (e)(2);

i. Revising paragraph (e)(3) introductory text;

j. Revising paragraph (e)(3)(i)(B);

k. Revising paragraph (e)(3)(iv)(C)(1);

l. Adding paragraphs (e)(3)(v);

m. Revising paragraph (e)(4) introductory text;

n. Revising paragraph (e)(4)(i);

o. Revising paragraph (e)(5);

p. Revising paragraph (f) introductory text;
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q. Adding paragraphs (f)(2) through (f)(6);

r. Revising paragraph (g) introductory text;

s. Revising paragraph (g)(1) and paragraph (g)(2) 

introductory text;

t. Revising paragraph (g)(2)(iii); 

u. Revising paragraph (g)(3); 

v. Adding paragraph (h); and

w. Adding paragraph (i) to read as follows:

§63.772 Test methods, compliance procedures, and compliance 

demonstrations.

* * * * *

(b) Determination of glycol dehydration unit flowrate, 

benzene emissions, or BTEX emissions. The procedures of 

this paragraph shall be used by an owner or operator to 

determine glycol dehydration unit natural gas flowrate, 

benzene emissions, or BTEX emissions. 

(1) * * *

* * * * *

(ii) The owner or operator shall document, to the 

Administrator's satisfaction, the actual annual average 

natural gas flowrate to the glycol dehydration unit.

* * * * *
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(2) The determination of actual average benzene or 

BTEX emissions from a glycol dehydration unit shall be made 

using the procedures of either paragraph (b)(2)(i) or 

(b)(2)(ii) of this section. Emissions shall be determined 

either uncontrolled, or with federally enforceable controls 

in place.

(i) The owner or operator shall determine actual 

average benzene or BTEX emissions using the model GRIGLYCalcTM , Version 3.0 or higher, and the procedures 

presented in the associated GRI-GLYCalcTM Technical 

Reference Manual. Inputs to the model shall be 

representative of actual operating conditions of the glycol 

dehydration unit and may be determined using the procedures 

documented in the Gas Research Institute (GRI) report 

entitled “Atmospheric Rich/Lean Method for Determining 

Glycol Dehydrator Emissions” (GRI–95/0368.1); or

(ii) The owner or operator shall determine an average 

mass rate of benzene or BTEX emissions in kilograms per 

hour through direct measurement using the methods in 

§63.772(a)(1)(i) or (ii), or an alternative method 

according to §63.7(f). Annual emissions in kilograms per 

year shall be determined by multiplying the mass rate by 
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Page 454 of 601

the number of hours the unit is operated per year. This 

result shall be converted to megagrams per year.

* * * * *

(d) Test procedures and compliance demonstrations for 

small glycol dehydration units. This paragraph applies to 

the test procedures for small dehydration units.

(1) If the owner or operator is using a control 

device to comply with the emission limit in 

§63.765(b)(1)(iii), the requirements of paragraph (e) of 

this section apply. Compliance is demonstrated using the 

methods specified in paragraph (f) of this section.

(2) If no control device is used to comply with the 

emission limit in §63.765(b)(1)(iii), the owner or operator 

must determine the glycol dehydration unit BTEX emissions 

as specified in paragraphs (d)(2)(i) through (iii) of this 

section. Compliance is demonstrated if the BTEX emissions 

determined as specified in paragraphs (d)(2)(i) through 

(iii) are less than the emission limit calculated using the 

equation in §63.765(b)(1)(iii).

(i) Method 1 or 1A, 40 CFR part 60, appendix A, as 

appropriate, shall be used for selection of the sampling 

sites at the outlet of the glycol dehydration unit process 
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vent. Any references to particulate mentioned in Methods 1 

and 1A do not apply to this section.

(ii) The gas volumetric flowrate shall be determined 

using Method 2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, 

as appropriate.

(iii) The BTEX emissions from the outlet of the 

glycol dehydration unit process vent shall be determined 

using the procedures specified in paragraph (e)(3)(v) of 

this section. As an alternative, the mass rate of BTEX at 

the outlet of the glycol dehydration unit process vent may 

be calculated using the model GRI-GLYCalcTM , Version 3.0 or 

higher, and the procedures presented in the associated GRIGLYCalcTM Technical Reference Manual. Inputs to the model 

shall be representative of actual operating conditions of 

the glycol dehydration unit and shall be determined using 

the procedures documented in the Gas Research Institute 

(GRI) report entitled “Atmospheric Rich/Lean Method for 

Determining Glycol Dehydrator Emissions” (GRI–95/0368.1). 

When the BTEX mass rate is calculated for glycol 

dehydration units using the model GRI-GLYCalcTM , all BTEX 

measured by Method 18, 40 CFR part 60, appendix A, shall be 

summed.
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(e) Control device performance test procedures. This 

paragraph applies to the performance testing of control 

devices. The owners or operators shall demonstrate that a 

control device achieves the performance requirements of 

§63.771(d)(1), (e)(3)(ii) or (f)(1) using a performance 

test as specified in paragraph (e)(3) of this section. 

Owners or operators using a condenser have the option to 

use a design analysis as specified in paragraph (e)(4) of 

this section. The owner or operator may elect to use the 

alternative procedures in paragraph (e)(5) of this section 

for performance testing of a condenser used to control 

emissions from a glycol dehydration unit process vent. As 

an alternative to conducting a performance test under this 

section for combustion control devices, a control device 

that can be demonstrated to meet the performance 

requirements of §63.771(d)(1), (e)(3)(ii) or (f)(1) through 

a performance test conducted by the manufacturer, as 

specified in paragraph (h) of this section can be used.

(1) * * *

(i) Except as specified in paragraph (e)(2) of this 

section, a flare, as defined in §63.761, that is designed 

and operated in accordance with §63.11(b);
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(ii) Except for control devices used for small glycol 

dehydration units, a boiler or process heater with a design 

heat input capacity of 44 megawatts or greater;

(iii) Except for control devices used for small glycol 

dehydration units, a boiler or process heater into which 

the vent stream is introduced with the primary fuel or is 

used as the primary fuel;

(iv) Except for control devices used for small glycol 

dehydration units, a boiler or process heater burning 

hazardous waste for which the owner or operator has either 

been issued a final permit under 40 CFR part 270 and 

complies with the requirements of 40 CFR part 266, subpart 

H; or has certified compliance with the interim status 

requirements of 40 CFR part 266, subpart H;

(v) Except for control devices used for small glycol 

dehydration units, a hazardous waste incinerator for which 

the owner or operator has been issued a final permit under 

40 CFR part 270 and complies with the requirements of 40 

CFR part 264, subpart O; or has certified compliance with 

the interim status requirements of 40 CFR part 265, subpart 

O.

* * * * *
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(2) An owner or operator shall design and operate each 

flare, as defined in §63.761, in accordance with the 

requirements specified in §63.11(b) and the compliance 

determination shall be conducted using Method 22 of 40 CFR 

part 60, appendix A, to determine visible emissions.

(3) For a performance test conducted to demonstrate 

that a control device meets the requirements of 

§63.771(d)(1), (e)(3)(ii) or (f)(1), the owner or operator 

shall use the test methods and procedures specified in 

paragraphs (e)(3)(i) through (v) of this section. The 

initial and periodic performance tests shall be conducted 

according to the schedule specified in paragraph (e)(3)(vi) 

of this section.

(i) * * *

* * * * *

(B) To determine compliance with the enclosed 

combustion device total HAP concentration limit specified 

in §63.765(b)(1)(iii), or the BTEX emission limit specified 

in §63.771(f)(1) the sampling site shall be located at the 

outlet of the combustion device.

* * * * *

(iv) * * *
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* * * * *

(C) * * *

(1) The emission rate correction factor for excess 

air, integrated sampling and analysis procedures of Method 

3A or 3B, 40 CFR part 60, appendix A, shall be used to 

determine the oxygen concentration. The samples shall be 

taken during the same time that the samples are taken for 

determining TOC concentration or total HAP concentration.

* * * * *

(v) To determine compliance with the BTEX emission 

limit specified in §63.771(f)(1) the owner or operator 

shall use one of the following methods: Method 18, 40 CFR 

part 60, appendix A; ASTM D6420–99 (2004), as specified in 

§63.772(a)(1)(ii); or any other method or data that have 

been validated according to the applicable procedures in 

Method 301, 40 CFR part 63, appendix A. The following 

procedures shall be used to calculate BTEX emissions:

(A) The minimum sampling time for each run shall be 1 

hour in which either an integrated sample or a minimum of 

four grab samples shall be taken. If grab sampling is used, 

then the samples shall be taken at approximately equal 
*** E.O. 12866 Review 

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intervals in time, such as 15

run.

(B) The mass rate of BTEX (E

the equations and procedures specified in paragraphs 

(e)(3)(v)(B)(1) and (

(1) The following equation shall be used:

Where:

Eo= Mass rate of BTEX at the outlet of the control device, 

dry basis, kilogram per hour.

Coj= Concentration of sample component j of the gas stream 

at the outlet of the control device, dry basis, parts per 

million by volume.

Moj= Molecular weight of sample component j of the

stream at the outlet of the control device, gram/gram

Qo= Flowrate of gas stream at the outlet of the control 

device, dry standard cubic meter per minute.

K2= Constant, 2.494×10

standard cubic meter) (kilogra

standard temperature (gram

is 20 degrees C.

n = Number of components in sample.

(2) When the BTEX mass rate is calculated, only BTEX 

compounds measured by Method 18, 40 CFR part 60, appendix 

A, or ASTM D6420–99 (2004) as specified in 

§63.772(a)(1)(ii), shall be summed using the equations in 

paragraph (e)(3)(v)(B)(

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intervals in time, such as 15-minute intervals during the 

(B) The mass rate of BTEX (Eo) shall be computed using 

the equations and procedures specified in paragraphs 

) and (2) of this section. 

) The following equation shall be used:

EX at the outlet of the control device, 

dry basis, kilogram per hour.

= Concentration of sample component j of the gas stream 

at the outlet of the control device, dry basis, parts per 

= Molecular weight of sample component j of the gas 

stream at the outlet of the control device, gram/gram

= Flowrate of gas stream at the outlet of the control 

device, dry standard cubic meter per minute.

= Constant, 2.494×10−6 (parts per million) (gram-mole per 

standard cubic meter) (kilogram/gram) (minute/hour), where 

standard temperature (gram-mole per standard cubic meter) 

n = Number of components in sample.

) When the BTEX mass rate is calculated, only BTEX 

compounds measured by Method 18, 40 CFR part 60, appendix 

99 (2004) as specified in 

§63.772(a)(1)(ii), shall be summed using the equations in 

paragraph (e)(3)(v)(B)(1) of this section.

Do Not Cite, 

minute intervals during the 

) shall be computed using 

the equations and procedures specified in paragraphs 

EX at the outlet of the control device, 

= Concentration of sample component j of the gas stream 

at the outlet of the control device, dry basis, parts per 

gas 

stream at the outlet of the control device, gram/gram-mole.

= Flowrate of gas stream at the outlet of the control 

mole per 

m/gram) (minute/hour), where 

mole per standard cubic meter) 

) When the BTEX mass rate is calculated, only BTEX 

compounds measured by Method 18, 40 CFR part 60, appendix 

§63.772(a)(1)(ii), shall be summed using the equations in 
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(vi) The owner or operator shall conduct performance 

tests according to the schedule specified in paragraphs 

(e)(3)(vi)(A) and (B) of this section.

(A) An initial performance test shall be conducted 

within 180 days after the compliance date that is specified 

for each affected source in §63.760(f)(7) through (8), 

except that the initial performance test for existing 

combustion control devices at existing major sources shall 

be conducted no later than 3 years after the date of 

publication of the final rule in the Federal Register. If 

the owner or operator of an existing combustion control 

device at an existing major source chooses to replace such 

device with a control device whose model is tested under 

§63.772(h), then the newly installed device shall comply 

with all provisions of this subpart no later than 3 years 

after the date of publication of the final rule in the 

Federal Register. The performance test results shall be 

submitted in the Notification of Compliance Status Report 

as required in §63.775(d)(1)(ii).

(B) Periodic performance tests shall be conducted for 

all control devices required to conduct initial performance 

tests except as specified in paragraphs (e)(3)(vi)(B)(1) 
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and (2) of this section. The first periodic performance 

test shall be conducted no later than 60 months after the 

initial performance test required in paragraph 

(e)(3)(vi)(A) of this section. Subsequent periodic

performance tests shall be conducted at intervals no longer 

than 60 months following the previous periodic performance 

test or whenever a source desires to establish a new 

operating limit. The periodic performance test results must 

be submitted in the next Periodic Report as specified in 

§63.775(e)(2)(xi). Combustion control devices meeting the 

criteria in either paragraph (e)(3)(vi)(B)(1) or (2) of 

this section are not required to conduct periodic 

performance tests.

(1) A control device whose model is tested under, and 

meets the criteria of, §63.772(h), or

(2) A combustion control device tested under 

§63.772(e) that meets the outlet TOC or HAP performance 

level specified in §63.771(d)(1)(i)(B) and that establishes 

a correlation between firebox or combustion chamber 

temperature and the TOC or HAP performance level.

(4) For a condenser design analysis conducted to meet 

the requirements of §63.771(d)(1), (e)(3)(ii), or (f)(1), 
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the owner or operator shall meet the requirements specified 

in paragraphs (e)(4)(i) and (e)(4)(ii) of this section. 

Documentation of the design analysis shall be submitted as 

a part of the Notification of Compliance Status Report as 

required in §63.775(d)(1)(i).

(i) The condenser design analysis shall include an 

analysis of the vent stream composition, constituent 

concentrations, flowrate, relative humidity, and 

temperature, and shall establish the design outlet organic 

compound concentration level, design average temperature of 

the condenser exhaust vent stream, and the design average 

temperatures of the coolant fluid at the condenser inlet 

and outlet. As an alternative to the condenser design 

analysis, an owner or operator may elect to use the 

procedures specified in paragraph (e)(5) of this section.

* * * * *

(5) As an alternative to the procedures in paragraph 

(e)(4)(i) of this section, an owner or operator may elect 

to use the procedures documented in the GRI report 

entitled, “Atmospheric Rich/Lean Method for Determining 

Glycol Dehydrator Emissions” (GRI–95/0368.1) as inputs for 
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the model GRI-GLYCalcTM , Version 3.0 or higher, to generate 

a condenser performance curve.

(f) Compliance demonstration for control device 

performance requirements. This paragraph applies to the 

demonstration of compliance with the control device 

performance requirements specified in §63.771(d)(1)(i), 

(e)(3) and (f)(1). Compliance shall be demonstrated using 

the requirements in paragraphs (f)(1) through (3) of this 

section. As an alternative, an owner or operator that 

installs a condenser as the control device to achieve the 

requirements specified in §63.771(d)(1)(ii), (e)(3) or 

(f)(1) may demonstrate compliance according to paragraph 

(g) of this section. An owner or operator may switch 

between compliance with paragraph (f) of this section and 

compliance with paragraph (g) of this section only after at 

least 1 year of operation in compliance with the selected 

approach. Notification of such a change in the compliance 

method shall be reported in the next Periodic Report, as 

required in §63.775(e), following the change.

* * * * *

(2) The owner or operator shall calculate the daily 

average of the applicable monitored parameter in accordance 
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with §63.773(d)(4) except that the inlet gas flow rate to 

the control device shall not be averaged.

(3) Compliance with the operating parameter limit is 

achieved when the daily average of the monitoring parameter 

value calculated under paragraph (f)(2) of this section is 

either equal to or greater than the minimum or equal to or 

less than the maximum monitoring value established under 

paragraph (f)(1) of this section. For inlet gas flow rate, 

compliance with the operating parameter limit is achieved 

when the value is equal to or less than the value 

established under §63.772(h).

(4) Except for periods of monitoring system 

malfunctions, repairs associated with monitoring system 

malfunctions, and required monitoring system quality 

assurance or quality control activities (including, as 

applicable, system accuracy audits and required zero and 

span adjustments), the CMS required in §63.773(d) must be 

operated at all times the affected source is operating. A 

monitoring system malfunction is any sudden, infrequent, 

not reasonably preventable failure of the monitoring system 

to provide valid data. Monitoring system failures that are 

caused in part by poor maintenance or careless operation 
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are not malfunctions. Monitoring system repairs are 

required to be completed in response to monitoring system 

malfunctions and to return the monitoring system to 

operation as expeditiously as practicable.

(5) Data recorded during monitoring system 

malfunctions, repairs associated with monitoring system 

malfunctions, or required monitoring system quality 

assurance or control activities may not be used in 

calculations used to report emissions or operating levels. 

All the data collected during all other required data 

collection periods must be used in assessing the operation 

of the control device and associated control system. 

(6) Except for periods of monitoring system 

malfunctions, repairs associated with monitoring system 

malfunctions, and required quality monitoring system 

quality assurance or quality control activities (including, 

as applicable, system accuracy audits and required zero and 

span adjustments), failure to collect required data is a 

deviation of the monitoring requirements.

(g) Compliance demonstration with percent reduction or 

emission limit performance requirements—condensers. This 

paragraph applies to the demonstration of compliance with 
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the performance requirements specified in 

§63.771(d)(1)(ii),(e)(3) or (f)(1) for condensers. 

Compliance shall be demonstrated using the procedures in 

paragraphs (g)(1) through (3) of this section.

(1) The owner or operator shall establish a sitespecific condenser performance curve according to 

§63.773(d)(5)(ii). For sources required to meet the BTEX 

limit in accordance with §63.771(e) or (f)(1) the owner or 

operator shall identify the minimum percent reduction 

necessary to meet the BTEX limit.

(2) Compliance with the requirements in 

§63.771(d)(1)(ii),(e)(3) or (f)(1) shall be demonstrated by 

the procedures in paragraphs (g)(2)(i) through (iii) of 

this section.

* * * * *

(iii) Except as provided in paragraphs (g)(2)(iii)(A) 

and (B) of this section, at the end of each operating day, 

the owner or operator shall calculate the 365-day average 

HAP, or BTEX, emission reduction, as appropriate, from the 

condenser efficiencies as determined in paragraph 

(g)(2)(ii) of this section for the preceding 365 operating 

days. If the owner or operator uses a combination of 
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process modifications and a condenser in accordance with 

the requirements of §63.771(e), the 365-day average HAP, or 

BTEX, emission reduction shall be calculated using the 

emission reduction achieved through process modifications 

and the condenser efficiency as determined in paragraph 

(g)(2)(ii) of this section, both for the previous 365 

operating days.

(A) After the compliance dates specified in 

§63.760(f), an owner or operator with less than 120 days of 

data for determining average HAP, or BTEX, emission 

reduction, as appropriate, shall calculate the average HAP, 

or BTEX emission reduction, as appropriate, for the first 

120 days of operation after the compliance dates. For 

sources required to meet the overall 95.0 percent reduction 

requirement, compliance is achieved if the 120-day average 

HAP emission reduction is equal to or greater than 90.0 

percent. For sources required to meet the BTEX limit under 

§63.765(b)(1)(iii), compliance is achieved if the average 

BTEX emission reduction is at least 95.0 percent of the 

required 365-day value identified under paragraph (g)(1) of 

this section (i.e., at least 76.0 percent if the 365-day 

design value is 80.0 percent).
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(B) After 120 days and no more than 364 days of 

operation after the compliance dates specified in 

§63.760(f), the owner or operator shall calculate the 

average HAP emission reduction as the HAP emission 

reduction averaged over the number of days between the 

current day and the applicable compliance date. For sources 

required to meet the overall 95.0-percent reduction 

requirement, compliance with the performance requirements 

is achieved if the average HAP emission reduction is equal 

to or greater than 90.0 percent. For sources required to 

meet the BTEX limit under §63.765(b)(1)(iii), compliance is 

achieved if the average BTEX emission reduction is at least 

95.0 percent of the required 365-day value identified under 

paragraph (g)(1) of this section (i.e., at least 76.0 

percent if the 365-day design value is 80.0 percent). 

(3) If the owner or operator has data for 365 days or 

more of operation, compliance is achieved based on the 

applicable criteria in paragraphs (g)(3)(i) or (ii) of this 

section.

(i) For sources meeting the HAP emission reduction 

specified in §63.771(d)(1)(ii) or (e)(3) the average HAP 
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emission reduction calculated in paragraph (g)(2)(iii) of 

this section is equal to or greater than 95.0 percent.

(ii) For sources required to meet the BTEX limit under 

§63.771(e)(3) or (f)(1), compliance is achieved if the 

average BTEX emission reduction calculated in paragraph 

(g)(2)(iii) of this section is equal to or greater than the 

minimum percent reduction identified in paragraph (g)(1) of 

this section.

* * * * *

(h) Performance testing for combustion control devices -

manufacturers’ performance test. 

(1) This paragraph applies to the performance testing 

of a combustion control device conducted by the device 

manufacturer. The manufacturer shall demonstrate that a

specific model of control device achieves the performance 

requirements in (h)(7) of this section by conducting a 

performance test as specified in paragraphs (h)(2) through 

(6) of this section. 

(2) Performance testing shall consist of three onehour (or longer) test runs for each of the four following 

firing rate settings making a total of 12 test runs per 

test. Propene (propylene) gas shall be used for the testing 
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fuel. All fuel analyses shall be performed by an 

independent third-party laboratory (not affiliated with the 

control device manufacturer or fuel supplier).

(i) 90 - 100 percent of maximum design rate (fixed 

rate).

(ii) 70 - 100 - 70 percent (ramp up, ramp down). Begin 

the test at 70 percent of the maximum design rate. Within 

the first 5 minutes, ramp the firing rate to 100 percent of 

the maximum design rate. Hold at 100 percent for 5 minutes. 

In the 10-15 minute time range, ramp back down to 70 

percent of the maximum design rate. Repeat three more times 

for a total of 60 minutes of sampling.

(iii) 30 - 70 - 30 percent (ramp up, ramp down). Begin 

the test at 30 percent of the maximum design rate. Within 

the first 5 minutes, ramp the firing rate to 70 percent of 

the maximum design rate. Hold at 70 percent for 5 minutes. 

In the 10-15 minute time range, ramp back down to 30 

percent of the maximum design rate. Repeat three more times 

for a total of 60 minutes of sampling.

(iv) 0 - 30 - 0 percent (ramp up, ramp down). Begin 

the test at 0 percent of the maximum design rate. Within 

the first 5 minutes, ramp the firing rate to 100 percent of 
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the maximum design rate. Hold at 30 percent for 5 minutes. 

In the 10-15 minute time range, ramp back down to 0 percent 

of the maximum design rate. Repeat three more times for a 

total of 60 minutes of sampling.

(3) All models employing multiple enclosures shall be 

tested simultaneously and with all burners operational. 

Results shall be reported for the each enclosure 

individually and for the average of the emissions from all 

interconnected combustion enclosures/chambers. Control 

device operating data shall be collected continuously 

throughout the performance test using an electronic Data 

Acquisition System and strip chart. Data shall be submitted 

with the test report in accordance with paragraph (8)(iii) 

of this section.

(4) Inlet testing shall be conducted as specified in 

paragraphs (4)(i) through (iii) of this section.

(i) The fuel flow metering system shall be located in 

accordance with Method 2A, 40 CFR part 60, appendix A-1, 

(or other approved procedure) to measure fuel flow rate at 

the control device inlet location. The fitting for filling 

fuel sample containers shall be located a minimum of 8 pipe 

diameters upstream of any inlet fuel flow monitoring meter.
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(ii) Inlet flow rate shall be determined using Method 

2A, 40 CFR part 60, appendix A-1. Record the start and stop 

reading for each 60-minute THC test. Record the gas 

pressure and temperature at 5-minute intervals throughout 

each 60-minute THC test.

(iii) Inlet fuel sampling shall be conducted in 

accordance with the criteria in paragraphs (h)(4)(iii)(A) 

and (B) of this section.

(A) At the inlet fuel sampling location, securely 

connect a Silonite-coated stainless steel evacuated 

canister fitted with a flow controller sufficient to fill 

the canister over a 1 hour period. Filling shall be 

conducted as specified in the following: 

(1) Open the canister sampling valve at the beginning 

of the total hydrocarbon (THC) test, and close the canister 

at the end of the THC test.

(2) Fill one canister for each THC test run.

(3) Label the canisters individually and record on a 

chain of custody form.

(B) Each fuel sample shall be analyzed using the 

following methods. The results shall be included in the 

test report.
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(1) Hydrocarbon compounds containing between one and 

five atoms of carbon plus benzene using ASTM D1945-03.

(2) Hydrogen (H2), carbon monoxide (CO), carbon dioxide 

(CO2), nitrogen (N2), oxygen (O2) using ASTM D1945-03.

(3) Carbonyl sulfide, carbon disulfide plus mercaptans 

using ASTM D5504.

(4) Higher heating value using ASTM D3588-98 or ASTM 

D4891-89.

(5) Outlet testing shall be conducted in accordance 

with the criteria in paragraphs (h)(5)(i) through (v) of 

this section.

(i) Sampling and flowrate measured in accordance with 

the following:

(A) The outlet sampling location shall be a minimum of 

4 equivalent stack diameters downstream from the highest 

peak flame or any other flow disturbance, and a minimum of 

one equivalent stack diameter upstream of the exit or any 

other flow disturbance. A minimum of two sample ports shall 

be used. 

(B) Flow rate shall be measured using Method 1, 40 CFR 

part 60, Appendix 1, for determining flow measurement 

traverse point location; and Method 2, 40 CFR part 60, 
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Appendix 1, shall be used to measure duct velocity. If low 

flow conditions are encountered (i.e., velocity pressure 

differentials less than 0.05 inches of water) during the 

performance test, a more sensitive manometer shall be used 

to obtain an accurate flow profile.

(ii) Molecular weight shall be determined as specified 

in paragraphs (h)(4)(iii)(B), (5)(ii)(A) and (B) of this 

section.

(A) An integrated bag sample shall be collected during 

the Method 4, 40 CFR part 60, Appendix A, moisture test. 

Analyze the bag sample using a gas chromatograph-thermal 

conductivity detector (GC-TCD) analysis meeting the 

following criteria:

(1) Collect the integrated sample throughout the 

entire test, and collect representative volumes from each 

traverse location.

(2) The sampling line shall be purged with stack gas 

before opening the valve and beginning to fill the bag.

(3) The bag contents shall be kneaded or 

otherwise vigorously mixed prior to the GC analysis.

(4) The GC-TCD calibration procedure in Method 3C, 40 

CFR part 60, Appendix A, shall be modified by using EPAAlt-
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045 as follows: For the initial calibration, triplicate 

injections of any single concentration must agree within 5 

percent of their mean to be valid. The calibration response 

factor for a single concentration re-check must be within 

10 percent of the original calibration response factor for 

that concentration. If this criterion is not met, the 

initial calibration using at least three concentration 

levels shall be repeated.

(B) Report the molecular weight of: O2, CO2, methane 

(CH4), and N2 and include in the test report submitted under 

§63.775(d)(iii). Moisture shall be determined using Method 

4, 40 CFR part 60, Appendix A. Traverse both ports with the 

Method 4, 40 CFR part 60, Appendix A, sampling train during 

each test run. Ambient air shall not be introduced into the 

Method 3C, 40 CFR part 60, Appendix A, integrated bag 

sample during the port change.

(iv) Carbon monoxide shall be determined using Method 

10, 40 CFR part 60, Appendix A. The test shall be run at 

the same time and with the sample points used for the EPA 

Method 25A, 40 CFR part 60, Appendix A, testing. An 

instrument range of 0-10 per million by volume-dry (ppmvd) 

shall be used.
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(v) Visible emissions shall be determined using Method 

22, 40 CFR part 60, Appendix A. The test shall be performed 

continuously during each test run. A digital color 

photograph of the exhaust point, taken from the position of 

the observer and annotated with date and time, will be 

taken once per test run and the four photos included in the 

test report.

(6) Total hydrocarbons (THC) shall be determined as 

specified by the following criteria:

(i) Conduct THC sampling using Method 25A, 40 CFR part 

60, Appendix A, except the option for locating the probe in 

the center 10 percent of the stack shall not be allowed. 

The THC probe must be traversed to 16.7 percent, 50 

percent, and 83.3 percent of the stack diameter during the 

testing.

(ii) A valid test shall consist of three Method 25A, 

40 CFR part 60, Appendix A, tests, each no less than 60 

minutes in duration.

(iii) A 0-10 parts per million by volume-wet (ppmvw) 

(as propane) measurement range is preferred; as an 

alternative a 0-30 ppmvw (as carbon) measurement range may 

be used.
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(iv) Calibration gases will be propane in air and be 

certified through EPA Protocol 1 – “EPA Traceability 

Protocol for Assay and Certification of Gaseous Calibration 

Standards,” September 1997, as amended August 25, 1999, 

EPA–600/R–97/121 (or more recent if updated since 1999).

(v) THC measurements shall be reported in terms of 

ppmvw as propane.

(vi) THC results shall be corrected to 3 percent CO2, 

as measured by Method 3C, 40 CFR part 60, Appendix A.

(vii) Subtraction of methane/ethane from the THC data 

is not allowed in determining results.

(7) Performance test criteria:

(i) The control device model tested must meet the 

criteria in paragraphs (h)(7)(i)(A) through (C) of this 

section:

(A) Method 22, 40 CFR part 60, Appendix A, results 

under paragraph (h)(5)(v) of this section with no 

indication of visible emissions, and

(B) Average Method 25A, 40 CFR part 60, Appendix A, 

results under paragraph (h)(6) of this section equal to or 

less than 10.0 ppmvw THC as propane corrected to 3.0 

percent CO2, and 
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(C) Average CO emissions determined under paragraph 

(h)(5)(iv) of this section equal to or less than 10 parts 

ppmvd, corrected to 3.0 percent CO2.

(ii) The manufacturer shall determine a maximum inlet 

gas flow rate which shall not be exceeded for each control 

device model to achieve the criteria in paragraph (h)(7)(i) 

of this section.

(iii) A control device meeting the criteria in 

paragraph (h)(7)(i)(A) through (C) of this section will 

have demonstrated a destruction efficiency of 98.0 percent 

for HAP regulated under this subpart.

(8) The owner or operator of a combustion control 

device model tested under this section shall submit the 

information listed in paragraphs (h)(8)(i) through (iii) in 

the test report required under §63.775(d)(1)(iii).

(i) Full schematic of the control device and 

dimensions of the device components.

(ii) Design net heating value (minimum and maximum) of 

the device.

(iii) Test fuel gas flow range (in both mass and 

volume). Include the minimum and maximum allowable inlet 

gas flow rate.
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(iv) Air/stream injection/assist ranges, if used.

(v) The test parameter ranges listed in paragraphs 

(h)(8)(vi)(A) through (O) of this section, as applicable 

for the tested model. 

(A) Fuel gas delivery pressure and temperature.

(B) Fuel gas moisture range.

(C) Purge gas usage range.

(D) Condensate (liquid fuel) separation range.

(E) Combustion zone temperature range. This is 

required for all devices that measure this parameter.

(F) Excess combustion air range.

(G) Flame arrestor(s).

(H) Burner manifold pressure.

(I) Pilot flame sensor.

(J) Pilot flame design fuel and fuel usage.

(K) Tip velocity range.

(L) Momentum flux ratio.

(M) Exit temperature range.

(N) Exit flow rate.

(O) Wind velocity and direction.

(vi) The test report shall include all calibration 

quality assurance/quality control data, calibration gas 
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values, gas cylinder certification, and strip charts 

annotated with test times and calibration values. 

(i) Compliance demonstration for combustion control 

devices - manufacturers’ performance test. This paragraph 

applies to the demonstration of compliance for a combustion 

control device tested under the provisions in paragraph (h) 

of this section. Owners or operators shall demonstrate that 

a control device achieves the performance requirements of 

§63.771(d)(1), (e)(3)(ii) or (f)(1), by installing a device 

tested under paragraph (h) of this section and complying 

with the following criteria: 

(1) The inlet gas flow rate shall meet the range 

specified by the manufacturer. Flow rate shall be measured 

as specified in §63.773(d)(3)(i)(H)(1).

(2) A pilot flame shall be present at all times of 

operation. The pilot flame shall be monitored in accordance 

with §63.773(d)(3)(i)(H)(2).

(3) Devices shall be operated with no visible 

emissions, except for periods not to exceed a total of 5 

minutes during any 2 consecutive hours. A visible emissions 

test using Method 22, 40 CFR part 60, Appendix A, shall be 
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performed monthly. The observation period shall be 2 hours 

and shall be used according to Method 22. 

(4) Compliance with the operating parameter limit is 

achieved when the following criteria are met:

(i) The inlet gas flow rate monitored under paragraph 

(i)(1) of this section is equal to or below the maximum 

established by the manufacturer; and

(ii) The pilot flame is present at all times; and

(iii) During the visible emissions test performed 

under paragraph (i)(3) of this section the duration of 

visible emissions does not exceed a total of 5 minutes 

during the observation period. Devices failing the visible 

emissions test shall follow the requirements in paragraphs 

(i)(4)(iii)(A) and (B) of this section.

(A) Following the first failure, the fuel nozzle(s) 

and burner tubes shall be replaced. 

(B) If, following replacement of the fuel nozzle(s) 

and burner tubes as specified in paragraph (i)(4)(iii)(A), 

the visible emissions test is not passed in the next 

scheduled test, either a performance test shall be 

performed under paragraph (e) of this section, or the 

device shall be replaced with another control device whose 
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model was tested, and meets, the requirements in paragraph 

(h) of this section.

19. Section 63.773 is amended by:

a. Revising paragraph (b);

b. Revising paragraph (d)(1) introductory text;

c. Revising paragraph (d)(1)(ii) and adding paragraphs 

(d)(1)(iii) and (iv);

d. Revising paragraphs (d)(2)(i) and (d)(2)(ii);

e. Revising paragraphs (d)(3)(i)(A) and (B);

f. Revising paragraphs (d)(3)(i)(D) and (E);

g. Revising paragraphs (d)(3)(i)(F)(1) and (2);

h. Revising paragraph (d)(3)(i)(G);

i. Adding paragraph (d)(3)(i)(H);

j. Revising paragraph (d)(4);

k. Revising paragraph (d)(5)(i) introductory text;

l. Revising paragraphs (d)(5)(i)(A) and (B);

m. Adding paragraph (d)(5)(i)(C);

n. Revising paragraphs (d)(5)(ii)(A) through (C);

o. Revising paragraphs (d)(6)(ii) and (iii);

p. Adding paragraph (d)(6)(vi);

q. Revising paragraph (d)(8)(i)(A); and

r. Revising paragraph (d)(8)(ii) to read as follows:
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§63.773 Inspection and monitoring requirements.

* * * * *

(b) The owner or operator of a control device whose 

model was tested under 63.772(h) shall develop an 

inspection and maintenance plan for each control device. 

At a minimum, the plan shall contain the control device 

manufacturer’s recommendations for ensuring proper 

operation of the device. Semi-annual inspections shall be 

conducted for each control device with maintenance and 

replacement of control device components made in accordance 

with the plan.

(d) Control device monitoring requirements. (1) For 

each control device, except as provided for in paragraph 

(d)(2) of this section, the owner or operator shall install 

and operate a continuous parameter monitoring system in 

accordance with the requirements of paragraphs (d)(3) 

through (9) of this section. Owners or operators that 

install and operate a flare in accordance with

§63.771(d)(1)(iii) or (f)(1)(iii) are exempt from the 

requirements of paragraphs (d)(4) and (5) of this section. 

The continuous monitoring system shall be designed and 

operated so that a determination can be made on whether the 
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control device is achieving the applicable performance 

requirements of §63.771(d), (e)(3) or (f)(1). Each 

continuous parameter monitoring system shall meet the 

following specifications and requirements:

* * * * *

(ii) A site-specific monitoring plan must be prepared 

that addresses the monitoring system design, data 

collection, and the quality assurance and quality control 

elements outlined in paragraph (d) of this section and in 

§63.8(d). Each CPMS must be installed, calibrated, 

operated, and maintained in accordance with the procedures 

in your approved site-specific monitoring plan. Using the 

process described in §63.8(f)(4), you may request approval 

of monitoring system quality assurance and quality control 

procedures alternative to those specified in paragraphs 

(d)(1)(ii)(A) through (E) of this section in your sitespecific monitoring plan.

(A) The performance criteria and design specifications 

for the monitoring system equipment, including the sample 

interface, detector signal analyzer, and data acquisition 

and calculations;
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(B) Sampling interface (e.g., thermocouple) location 

such that the monitoring system will provide representative 

measurements; 

(C) Equipment performance checks, system accuracy 

audits, or other audit procedures;

(D) Ongoing operation and maintenance procedures in 

accordance with provisions in §63.8(c)(1) and (c)(3); and

(E) Ongoing reporting and recordkeeping procedures in 

accordance with provisions in §63.10(c), (e)(1), and 

(e)(2)(i).

(iii) The owner or operator must conduct the CPMS 

equipment performance checks, system accuracy audits, or 

other audit procedures specified in the site-specific 

monitoring plan at least once every 12 months.

(iv) The owner or operator must conduct a performance 

evaluation of each CPMS in accordance with the sitespecific monitoring plan.

(2) * * *

(i) Except for control devices for small glycol 

dehydration units, a boiler or process heater in which all 

vent streams are introduced with the primary fuel or is 

used as the primary fuel; or
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(ii) Except for control devices for small glycol 

dehydration units, a boiler or process heater with a design 

heat input capacity equal to or greater than 44 megawatts.

(3) * * *

(i) * * *

(A) For a thermal vapor incinerator that demonstrates 

during the performance test conducted under §63.772(e) that 

the combustion zone temperature is an accurate indicator of 

performance, a temperature monitoring device equipped with 

a continuous recorder. The monitoring device shall have a 

minimum accuracy of ±1 percent of the temperature being 

monitored in degrees C, or ±2.5 degrees C, whichever value 

is greater. The temperature sensor shall be installed at a 

location representative of the combustion zone temperature.

(B) For a catalytic vapor incinerator, a temperature 

monitoring device equipped with a continuous recorder. The 

device shall be capable of monitoring temperature at two 

locations and have a minimum accuracy of ±1 percent of the 

temperature being monitored in degrees C, or ±2.5 degrees 

C, whichever value is greater. One temperature sensor shall 

be installed in the vent stream at the nearest feasible 

point to the catalyst bed inlet and a second temperature 
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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 a temperature 

monitoring device equipped with a continuous recorder. The 

temperature monitoring device shall have a minimum accuracy 

of ±1 percent of the temperature being monitored in degrees 

C, or ±2.5 degrees C, whichever value is greater. The 

temperature sensor shall be installed at a location 

representative of the combustion zone temperature.

(E) For a condenser, a temperature monitoring device 

equipped with a continuous recorder. The temperature 

monitoring device shall have a minimum accuracy of ±1 

percent of the temperature being monitored in degrees C, or 

±2.8 degrees C, whichever value is greater. The temperature 

sensor shall be installed at a location in the exhaust vent 

stream from the condenser.

(F) * * *

(1) A continuous parameter monitoring system to 

measure and record the average total regeneration stream 

mass flow or volumetric flow during each carbon bed 

regeneration cycle. The flow sensor must have a measurement 
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sensitivity of 5 percent of the flow rate or 10 cubic feet 

per minute, whichever is greater. The mechanical 

connections for leakage must be checked at least every 

month, and a visual inspection must be performed at least 

every 3 months of all components of the flow CPMS for 

physical and operational integrity and all electrical 

connections for oxidation and galvanic corrosion if your 

flow CPMS is not equipped with a redundant flow sensor; and

(2) A continuous parameter monitoring system to 

measure and record the average carbon bed temperature for 

the duration of the carbon bed steaming cycle and to 

measure the actual carbon bed temperature after 

regeneration and within 15 minutes of completing the 

cooling cycle. The temperature monitoring device shall have 

a minimum accuracy of ±1 percent of the temperature being 

monitored in degrees C, or ±2.5 degrees C, whichever value 

is greater.

(G) For a nonregenerative-type carbon adsorption 

system, the owner or operator shall monitor the design 

carbon replacement interval established using a performance 

test performed in accordance with §63.772(e)(3) shall be 
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based on the total carbon working capacity of the control 

device and source operating schedule.

(H) For a control device model whose model is tested 

under §63.772(h):

(1) A continuous monitoring system that measures gas 

flow rate at the inlet to the control device. The 

monitoring instrument shall have an accuracy of plus or 

minus 2 percent or better.

(2) A heat sensing monitoring device equipped with a 

continuous recorder that indicates the continuous ignition 

of the pilot flame.

* * * * *

(4) Using the data recorded by the monitoring system, 

except for inlet gas flow rate, the owner or operator must 

calculate the daily average value for each monitored 

operating parameter for each operating day. If the 

emissions unit operation is continuous, the operating day 

is a 24-hour period. If the emissions unit operation is not 

continuous, the operating day is the total number of hours 

of control device operation per 24-hour period. Valid data 

points must be available for 75 percent of the operating 

hours in an operating day to compute the daily average.
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(5) For each operating parameter monitor installed in 

accordance with the requirements of paragraph (d)(3) of 

this section, the owner or operator shall comply with 

paragraph (d)(5)(i) of this section for all control 

devices, and when condensers are installed, the owner or 

operator shall also comply with paragraph (d)(5)(ii) of 

this section.

(i) The owner or operator shall establish a minimum 

operating parameter value or a maximum operating parameter 

value, as appropriate for the control device, to define the 

conditions at which the control device must be operated to 

continuously achieve the applicable performance 

requirements of §63.771(d)(1), (e)(3)(ii) or (f)(1). Each 

minimum or maximum operating parameter value shall be 

established as follows:

(A) If the owner or operator conducts performance 

tests in accordance with the requirements of §63.772(e)(3) 

to demonstrate that the control device achieves the 

applicable performance requirements specified in 

§63.771(d)(1), (e)(3)(ii) or (f)(1), then the minimum 

operating parameter value or the maximum operating 

parameter value shall be established based on values 
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measured during the performance test and supplemented, as 

necessary, by a condenser design analysis or control device 

manufacturer recommendations or a combination of both.

(B) If the owner or operator uses a condenser design 

analysis in accordance with the requirements of 

§63.772(e)(4) to demonstrate that the control device 

achieves the applicable performance requirements specified 

in §63.771(d)(1), (e)(3)(ii) or (f)(1), then the minimum 

operating parameter value or the maximum operating 

parameter value shall be established based on the condenser 

design analysis and may be supplemented by the condenser 

manufacturer's recommendations.

(C) If the owner or operator operates a control device 

where the performance test requirement was met under 

§63.772(h) to demonstrate that the control device achieves 

the applicable performance requirements specified in 

§63.771(d)(1), (e)(3)(ii) or (f)(1), then the maximum inlet 

gas flow rate shall be established based on the performance 

test and supplemented, as necessary, by the manufacturer 

recommendations.

(ii) * * *
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(A) If the owner or operator conducts a performance 

test in accordance with the requirements of §63.772(e)(3) 

to demonstrate that the condenser achieves the applicable 

performance requirements in §63.771(d)(1), (e)(3)(ii) or 

(f)(1), then the condenser performance curve shall be based 

on values measured during the performance test and 

supplemented as necessary by control device design 

analysis, or control device manufacturer's recommendations, 

or a combination or both.

(B) If the owner or operator uses a control device 

design analysis in accordance with the requirements of 

§63.772(e)(4)(i) to demonstrate that the condenser achieves 

the applicable performance requirements specified in 

§63.771(d)(1), (e)(3)(ii) or (f)(1), then the condenser 

performance curve shall be based on the condenser design 

analysis and may be supplemented by the control device 

manufacturer's recommendations.

(C) As an alternative to paragraph (d)(5)(ii)(B) of 

this section, the owner or operator may elect to use the 

procedures documented in the GRI report entitled, 

“Atmospheric Rich/Lean Method for Determining Glycol 

Dehydrator Emissions” (GRI–95/0368.1) as inputs for the 
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model GRI-GLYCalcTM , Version 3.0 or higher, to generate a 

condenser performance curve.

* * * * *

(6) * * *

* * * * *

(ii) For sources meeting §63.771(d)(1)(ii), an 

excursion occurs when the 365-day average condenser 

efficiency calculated according to the requirements 

specified in §63.772(g)(2)(iii) is less than 95.0 percent. 

For sources meeting §63.771(f)(1), an excursion occurs when 

the 365-day average condenser efficiency calculated 

according to the requirements specified in 

§63.772(g)(2)(iii) is less than 95.0 percent of the 

identified 365-day required percent reduction.

(iii) For sources meeting §63.771(d)(1)(ii), if an 

owner or operator has less than 365 days of data, an 

excursion occurs when the average condenser efficiency 

calculated according to the procedures specified in 

§63.772(g)(2)(iii)(A) or (B) is less than 90.0 percent. For 

sources meeting §63.771(d)(1)(ii), an excursion occurs when 

the 365-day average condenser efficiency calculated 

according to the requirements specified in 
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§63.772(g)(2)(iii) is less than the identified 365-day 

required percent reduction.

* * * * *

(vi) For control device whose model is tested under 

§63.772(h) an excursion occurs when:

(A) The inlet gas flow rate exceeds the maximum 

established during the test conducted under §63.772(h).

(B) Failure of the monthly visible emissions test 

conducted under §63.772(i)(3) occurs. 

* * * * *

(8) * * *

(i) * * *

(A) During a malfunction when the affected facility is 

operated during such period in accordance with §63.6(e)(1); 

or

* * * * *

(ii) For each control device, or combinations of 

control devices installed on the same emissions unit, one 

excused excursion is allowed per semiannual period for any 

reason. The initial semiannual period is the 6-month 

reporting period addressed by the first Periodic Report 
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submitted by the owner or operator in accordance with 

§63.775(e) of this subpart.

* * * * *

20. Section 63.774 is amended by:

a. Revising paragraph (b)(3) introductory text;

b. Deleting and reserving paragraph (b)(3)(ii);

c. Revising paragraph (b)(4)(ii) introductory text;

d. Adding paragraph (b)(4)(ii)(C);

e. Adding paragraph (b)(7)(ix); and

f. Adding paragraphs (g) and (h) to read as follows:

§63.774 Recordkeeping requirements.

* * * * *

(b) * * *

* * * * *

(3) Records specified in §63.10(c) for each monitoring 

system operated by the owner or operator in accordance with 

the requirements of §63.773(d). Notwithstanding the 

requirements of §63.10(c), monitoring data recorded during 

periods identified in paragraphs (b)(3)(i) through 

(b)(3)(iv) of this section shall not be included in any 

average or percent leak rate computed under this subpart. 

Records shall be kept of the times and durations of all 
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such periods and any other periods during process or 

control device operation when monitors are not operating or 

failed to collect required data.

* * * * *

(ii) [Reserved]

* * * * *

(4) * * *

* * * * *

(ii) Records of the daily average value of each 

continuously monitored parameter for each operating day 

determined according to the procedures specified in 

§63.773(d)(4) of this subpart, except as specified in 

paragraphs (b)(4)(ii)(A) through (C) of this section.

* * * * *

(C) For control device whose model is tested under 

§63.772(h), the records required in paragraph (h) of this 

section.

* * * * *

(7) * * *

(ix) Records identifying the carbon replacement 

schedule under §63.771(d)(5) and records of each carbon 

replacement.
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* * * * *

(g) The owner or operator of an affected source 

subject to this subpart shall maintain records of the 

occurrence and duration of each malfunction of operation 

(i.e., process equipment) or the air pollution control 

equipment and monitoring equipment. The owner or operator 

shall maintain records of actions taken during periods of 

malfunction to minimize emissions in accordance with 

§63.764(a), including corrective actions to restore 

malfunctioning process and air pollution control and 

monitoring equipment to its normal or usual manner of 

operation.

(h) Record the following when using a control device 

whose model is tested under §63.772(h) to comply with 

§63.771(d), (e)(3)(ii) and (f)(1):

(1) All visible emission readings and flowrate 

measurements made during the compliance determination 

required by §63.772(i); and

(2) All hourly records and other recorded periods when 

the pilot flame is absent.

(i) The date the semi-annual maintenance inspection 

required under §63.773(b) is performed. Include a list of 
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any modifications or repairs made to the control device 

during the inspection and other maintenance performed such 

as cleaning of the fuel nozzles.

21. Section 63.775 is amended by:

a. Revising paragraph (b)(1);

b. Revising paragraph (b)(6);

c. Deleting and reserving paragraph (b)(7);

d. Revising paragraph (c)(1);

e. Revising paragraph (c)(6);

f. Revising paragraph (c)(7)(i);

g. Revising paragraph (d)(1) introductory text;

h. Revising paragraph (d)(1)(i);

i. Revising paragraph (d)(1)(ii) introductory text;

j. Revising paragraph (d)(2)(ii);

k. Adding paragraph (d)(5)(iv);

l. Revising paragraph (d)(11);

m. Adding paragraphs (d)(13) and (d)(14);

n. Revising paragraphs (e)(2)(ii)(B) and (C);

o. Adding paragraphs (e)(2)(ii)(E) and (F);

p. Adding paragraphs (e)(2)(xi) and (xii); and

q. Adding paragraph (g) to read as follows:

§63.775 Reporting requirements.
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* * * * *

(b) * * *

(1) The initial notifications required for existing 

affected sources under §63.9(b)(2) shall be submitted as 

provided in paragraphs (b)(1)(i) and (ii) of this section.

(i) Except as otherwise provided in paragraph (ii), 

the initial notifications shall be submitted by 1 year 

after an affected source becomes subject to the provisions 

of this subpart or by June 17, 2000, whichever is later. 

Affected sources that are major sources on or before June 

17, 2000 and plan to be area sources by June 17, 2002 shall 

include in this notification a brief, nonbinding 

description of a schedule for the action(s) that are 

planned to achieve area source status. 

(ii) An affected source identified under §63.760(f)(7) 

or (9) shall submit an initial notification required for 

existing affected sources under §63.9(b)(2) within 1 year 

after the affected source becomes subject to the provisions 

of this subpart or by one year after publication of the 

final rule in the Federal Register, whichever is later. An 

affected source identified under §63.760(f)(7) or (9) that 

plans to be an area source by three years after publication 
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of the final rule in the Federal Register, shall include in 

this notification a brief, nonbinding description of a 

schedule for the action(s) that are planned to achieve area 

source status.

* * * * *

(6) If there was a malfunction during the reporting 

period, the Periodic Report specified in paragraph (e) of 

this section shall include the number, duration, and a 

brief description for each type of malfunction which 

occurred during the reporting period and which caused or 

may have caused any applicable emission limitation to be 

exceeded. The report must also include a description of 

actions taken by an owner or operator during a malfunction 

of an affected source to minimize emissions in accordance 

with §63.764(j), including actions taken to correct a 

malfunction.

(7) [Reserved]

* * * * *

(c) * * *

(1) The initial notifications required under 

§63.9(b)(2) not later than January 3, 2008. In addition to 

submitting your initial notification to the addressees 
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specified under §63.9(a), you must also submit a copy of 

the initial notification to the EPA's Office of Air Quality 

Planning and Standards. Send your notification via e-mail 

to Oil and Gas Sector@epa.gov or via U.S. mail or other 

mail delivery service to U.S. EPA, Sector Policies and 

Programs Division/Fuels and Incineration Group (E143–01), 

Attn: Oil and Gas Project Leader, Research Triangle Park, 

NC 27711.

* * * * *

(6) If there was a malfunction during the reporting 

period, the Periodic Report specified in paragraph (e) of 

this section shall include the number, duration, and a 

brief description for each type of malfunction which 

occurred during the reporting period and which caused or 

may have caused any applicable emission limitation to be 

exceeded. The report must also include a description of 

actions taken by an owner or operator during a malfunction 

of an affected source to minimize emissions in accordance 

with §63.764(j), including actions taken to correct a 

malfunction.

(7) * * *
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(i) Documentation of the source's location relative to 

the nearest UA plus offset and UC boundaries. This 

information shall include the latitude and longitude of the 

affected source; whether the source is located in an urban 

cluster with 10,000 people or more; the distance in miles 

to the nearest urbanized area boundary if the source is not 

located in an urban cluster with 10,000 people or more; and 

the name of the nearest urban cluster with 10,000 people or 

more and nearest urbanized area.

* * * * *

(d) * * *

(1) If a closed-vent system and a control device other 

than a flare are used to comply with §63.764, the owner or 

operator shall submit the information in paragraph 

(d)(1)(iii) of this section and the information in either 

paragraph (d)(1)(i) or (ii) of this section.

(i) The condenser design analysis documentation 

specified in §63.772(e)(4) of this subpart, if the owner or 

operator elects to prepare a design analysis.

(ii) If the owner or operator is required to conduct a 

performance test, the performance test results including 

the information specified in paragraphs (d)(1)(ii)(A) and 
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(B) of this section. Results of a performance test 

conducted prior to the compliance date of this subpart can

be used provided that the test was conducted using the 

methods specified in §63.772(e)(3) and that the test 

conditions are representative of current operating 

conditions. If the owner or operator operates a combustion 

control device model tested under §63.772(h), an electronic 

copy of the performance test results shall be submitted via 

email to Oil and Gas PT@EPA.GOV. 

* * * * *

(iii) 

(2) * * *

* * * * *

(ii) A statement of whether a flame, was present at 

the pilot light over the full period of the compliance 

determination.

(5) * * *

* * * * *

(ii) An explanation of the rationale for why the owner 

or operator selected each of the operating parameter values 

established in §63.773(d)(5). This explanation shall 

include any data and calculations used to develop the value 
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and a description of why the chosen value indicates that 

the control device is operating in accordance with the 

applicable requirements of §63.771(d)(1), (e)(3)(ii) or 

(f)(1).

* * * * *

(iv) For each carbon adsorber, the predetermined 

carbon replacement schedule as required in 

§63.771(d)(5)(i).

* * * * *

(11) The owner or operator shall submit the analysis 

prepared under §63.771(e)(2) to demonstrate the conditions 

by which the facility will be operated to achieve the HAP 

emission reduction of 95.0 percent, or the BTEX limit in 

§63.765(b)(1)(iii), through process modifications or a 

combination of process modifications and one or more 

control devices.

* * * * *

(13) If the owner or operator installs a combustion 

control device model tested under the procedures in 

§63.772(h), the data listed under §63.772(h)(8).

(14) For each combustion control device model tested 

under §63.772(h), the information listed in paragraphs 
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(d)(14)(i) through (vi) of this section.

(i) Name, address and telephone number of the control 

device manufacturer.

(ii) Control device model number.

(iii) Control device serial number.

(iv) Date of control device certification test.

(v) Manufacturer’s HAP destruction efficiency rating.

(vi) Control device operating parameters, maximum 

allowable inlet gas flowrate.

(e) * * *

* * * * *

(2) The owner or operator shall include the 

information specified in paragraphs (e)(2)(i) through 

(xiii) of this section, as applicable.

* * * * *

(ii) * * *

* * * * *

(B) For each excursion caused when the 365-day average 

condenser control efficiency is less than the value

specified in §63.773(d)(6)(ii), the report must include the 

365-day average values of the condenser control efficiency, 
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and the date and duration of the period that the excursion 

occurred.

(C) For each excursion caused when condenser control 

efficiency is less than the value specified in 

§63.773(d)(6)(iii), the report must include the average 

values of the condenser control efficiency, and the date 

and duration of the period that the excursion occurred.

* * * * *

(E) For each excursion caused when the maximum inlet 

gas flow rate identified under §63.772(h) is exceeded, the 

report must include the values of the inlet gas identified 

and the date and duration of the period that the excursion 

occurred.

(F) For each excursion caused when visible emissions 

determined under §63.772(i) exceed the maximum allowable 

duration, the report must include the date and duration of 

the period that the excursion occurred.

* * * * *

(xi) The results of any periodic test as required in 

§63.772(e)(3) conducted during the reporting period.

(xii) For each carbon adsorber used to meet the 

control device requirements of §63.771(d)(1), records of 
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each carbon replacement that occurred during the reporting 

period. 

(xiii) For combustion control device inspections 

conducted in accordance with §63.773(b) the records 

specified in §63.774(i).

* * * * *

(g) Electronic Reporting. (1) As of January 1, 2012 

and within 60 days after the date of completing each 

performance test, as defined in §63.2 and as required in 

this subpart, you must submit performance test data, except 

opacity data, electronically to the EPA’s Central Data 

Exchange (CDX) by using the Electronic Reporting Tool (ERT) 

(see http://www.epa.gov/ttn/chief/ert/ert tool.html/). Only 

data collected using test methods compatible with ERT are 

subject to this requirement to be submitted electronically 

into the EPA’s WebFIRE database. 

(2) All reports required by this subpart not subject 

to the requirements in paragraphs (g)(1) of this section 

must be sent to the Administrator at the appropriate 

address listed in §63.13. If acceptable to both the 

Administrator and the owner or operator of a source, these 

reports may be submitted on electronic media. The 
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Administrator retains the right to require submittal of 

reports subject to paragraph (g)(1) of this section in 

paper format.

* * * * *

22. Appendix to subpart HH of part 63 – Tables is 

amended by revising Table 2 to read as follows:

Appendix to Subpart HH of Part 63—Tables

* * * * *

Table 2 to Subpart HH of Part 63—Applicability of 40 CFR 

Part 63 General Provisions to Subpart HH

General provisions 

reference

Applicabl

e to 

subpart H

H Explanation

§63.1(a)(1) ...........Yes.

§63.1(a)(2) ...........Yes.

§63.1(a)(3) ...........Yes.

§63.1(a)(4) ...........Yes.

§63.1(a)(5) ...........No............................... Section reserved.

§63.1(a)(6) ...........Yes.

§63.1(a)(7) through ...

(a)(9)

No............................... Section reserved.

§63.1(a)(10) ..........Yes.

§63.1(a)(11) ..........Yes.

§63.1(a)(12) ..........Yes.

§63.1(b)(1) ...........No............................... Subpart HH specifies 

applicability.

§63.1(b)(2) ...........No............................... Section reserved.

§63.1(b)(3) ...........Yes.

§63.1(c)(1) ...........No............................... Subpart HH specifies 

applicability.

§63.1(c)(2) ...........Yes.............................. Subpart HH exempts area 

sources from the requirement 

to obtain a Title V permit 

unless otherwise required by 
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law as specified in 

§63.760(h).

§63.1(c)(3) and 

(c)(4) ................

No............................... Section reserved.

§63.1(c)(5) ...........Yes.

§63.1(d) ..............No............................... Section reserved.

§63.1(e) ..............Yes.

§63.2 .................Yes.............................. Except definition of major 

source is unique for this 

source category and there 

are additional definitions 

in subpart HH.

§63.3(a) through (c) ..Yes.

§63.4(a)(1) through ...

(a)(2)

Yes.

§63.4(a)(3) through ...

(a)(5)

No............................... Section reserved.

§63.4(b) ..............Yes.

§63.4(c) ..............Yes.

§63.5(a)(1) ...........Yes.

§63.5(a)(2) ...........Yes.

§63.5(b)(1) ...........Yes.

§63.5(b)(2) ...........No............................... Section reserved.

§63.5(b)(3) ...........Yes.

§63.5(b)(4) ...........Yes.

§63.5(b)(5) ...........No............................... Section Reserved.

§63.5(b)(6) ...........Yes.

§63.5(c) ..............No............................... Section reserved.

§63.5(d)(1) ...........Yes.

§63.5(d)(2) ...........Yes.

§63.5(d)(3) ...........Yes.

§63.5(d)(4) ...........Yes.

§63.5(e) ..............Yes.

§63.5(f)(1) ...........Yes.

§63.5(f)(2) ...........Yes.

§63.6(a) ..............Yes.

§63.6(b)(1) ...........Yes.

§63.6(b)(2) ...........Yes.

§63.6(b)(3) ...........Yes.

§63.6(b)(4) ...........Yes.

§63.6(b)(5) ...........Yes.

§63.6(b)(6) ...........No............................... Section reserved.

§63.6(b)(7) ...........Yes.

§63.6(c)(1) ...........Yes.
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§63.6(c)(2) ...........Yes.

§63.6(c)(3) through ...

(c)(4)

No............................... Section reserved.

§63.6(c)(5) ...........Yes.

§63.6(d) ..............No............................... Section reserved.

§63.6(e) ..............Yes.

§63.6(e)(1)(i) ........No............................... See §63.764(j) for general 

duty requirement.

§63.6(e)(1)(ii) .......No.

§63.6(e)(1)(iii) ......Yes.

§63.6(e)(2) ...........No............................... Section reserved.

§63.6(e)(3) ...........No.

§63.6(f)(1) ...........No

§63.6(f)(2) ...........Yes.

§63.6(f)(3) ...........Yes.

§63.6(g) ..............Yes.

§63.6(h) ..............No............................... Subpart HH does not contain 

opacity or visible emission 

standards.

§63.6(i)(1) through ...

(i)(14)

Yes.

§63.6(i)(15) ..........No............................... Section reserved.

§63.6(i)(16) ..........Yes.

§63.6(j) ..............Yes.

§63.7(a)(1) ...........Yes.

§63.7(a)(2) ...........Yes.............................. But the performance test 

results must be submitted 

within 180 days after the 

compliance date.

§63.7(a)(3) ...........Yes.

§63.7(b) ..............Yes.

§63.7(c) ..............Yes.

§63.7(d) ..............Yes.

§63.7(e)(1) ...........No.

§63.7(e)(2) ...........Yes.

§63.7(e)(3) ...........Yes.

§63.7(e)(4) ...........Yes.

§63.7(f) ..............Yes.

§63.7(g) ..............Yes.

§63.7(h) ..............Yes.

§63.8(a)(1) ...........Yes.

§63.8(a)(2) ...........Yes.

§63.8(a)(3) ...........No............................... Section reserved.

§63.8(a)(4) ...........Yes.
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§63.8(b)(1) ...........Yes.

§63.8(b)(2) ...........Yes.

§63.8(b)(3) ...........Yes.

§63.8(c)(1) ...........No.

§63.8(c)(1)(i)

§63.8(c)(1)(ii)

§63.8(c)(1)(iii) ......

No.

Yes.

Pending

§63.8(c)(2) ...........Yes.

§63.8(c)(3) ...........Yes.

§63.8(c)(4) ...........Yes.

§63.8(c)(4)(i) ........No............................... Subpart HH does not require 

continuous opacity monitors.

§63.8(c)(4)(ii) .......Yes.

§63.8(c)(5) through ...

(c)(8)

Yes.

§63.8(d) ..............Yes.

§63.8(d)(3) ...........Yes. Except for last sentence, 

which refers to an SSM plan. 

SSM plans are not required.

§63.8(e) ..............Yes Subpart HH does not 

specifically require 

continuous emissions monitor 

performance evaluation, 

however, the Administrator 

can request that one be 

conducted.

§63.8(f)(1) through ...

(f)(5)

Yes.

§63.8(f)(6) ...........Yes.

§63.8(g) ..............No............................... Subpart HH specifies 

continuous monitoring system 

data reduction requirements.

§63.9(a) ..............Yes.

§63.9(b)(1) ...........Yes.

§63.9(b)(2) ...........Yes.............................. Existing sources are given 1 

year (rather than 120 days) 

to submit this notification. 

Major and area sources that 

meet §63.764(e) do not have 

to submit initial 

notifications.

§63.9(b)(3) ...........No............................... Section reserved.

§63.9(b)(4) ...........Yes.

§63.9(b)(5) ...........Yes.
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§63.9(c) ..............Yes.

§63.9(d) ..............Yes.

§63.9(e) ..............Yes.

§63.9(f) ..............No............................... Subpart HH does not have 

opacity or visible emission 

standards.

§63.9(g)(1) ...........Yes.

§63.9(g)(2) ...........No............................... Subpart HH does not have 

opacity or visible emission 

standards.

§63.9(g)(3) ...........Yes.

§63.9(h)(1) through ...

(h)(3)

Yes.............................. Area sources located outside 

UA plus offset and UC 

boundaries are not required 

to submit notifications of 

compliance status.

§63.9(h)(4) ...........No............................... Section reserved.

§63.9(h)(5) through ...

(h)(6)

Yes.

§63.9(i) ..............Yes.

§63.9(j) ..............Yes.

§63.10(a) .............Yes.

§63.10(b)(1) ..........Yes.............................. §63.774(b)(1) requires 

sources to maintain the most 

recent 12 months of data onsite and allows offsite 

storage for the remaining 4 

years of data.

§63.10(b)(2) ..........Yes.

§63.10(b)(2)(i) .......No.

§63.10(b)(2)(ii) ......No............................... See §63.774(g) for 

recordkeeping of occurrence, 

duration, and actions taken 

during malfunctions.

§63.10(b)(2)(iii) .....Yes.

§63.10(b)(2)(iv) ......

through (b)(2)(v)

No.

§63.10(b)(2)(vi) ......

through (b)(2)(xiv)

Yes.

§63.10(b)(3) ..........Yes.............................. §63.774(b)(1) requires 

sources to maintain the most 

recent 12 months of data onsite and allows offsite 

storage for the remaining 4 
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years of data.

§63.10(c)(1) ..........Yes.

§63.10(c)(2) through

(c)(4)

No............................... Sections reserved.

§63.10(c)(5) through

(8) (c)(8)

Yes.

§63.10(c)(9) ..........No............................... Section reserved.

§63.10(c)(10) through

(11) 

No............................... See §63.774(g) for 

recordkeeping of 

malfunctions.

§63.10(c)(12) through

(14)

Yes.

§63.10(c)(15) .........No.

§63.10(d)(1) ..........Yes.

§63.10(d)(2) ..........Yes.............................. Area sources located outside 

UA plus offset and UC 

boundaries do not have to 

submit performance test 

reports.

§63.10(d)(3) ..........Yes.

§63.10(d)(4) ..........Yes.

§63.10(d)(5) ..........No............................... See §63.775(b)(6) or (c)(6) 

for reporting of 

malfunctions.

§63.10(e)(1) ..........Yes.............................. Area sources located outside 

UA plus offset and UC 

boundaries are not required 

to submit reports.

§63.10(e)(2) ..........Yes.............................. Area sources located outside 

UA plus offset and UC 

boundaries are not required 

to submit reports.

§63.10(e)(3)(i) .......Yes.............................. Subpart HH requires major 

sources to submit Periodic 

Reports semi-annually. Area 

sources are required to 

submit Periodic Reports 

annually. Area sources 

located outside UA plus 

offset and UC boundaries are 

not required to submit 

reports.

§63.10(e)(3)(i)(A) ....Yes.

§63.10(e)(3)(i)(B) ....Yes.
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§63.10(e)(3)(i)(C) ....No............................... Section reserved.

§63.10(e)(3)(ii) ......

through (viii)

Yes.

§63.10(f) .............Yes.

§63.11(a) and (b) .....Yes.

§63.11(c), (d), and 

(e)

Yes.

§63.12(a) through (c) Yes.

§63.13(a) through (c) Yes.

§63.14(a) and (b) .....Yes.

§63.15(a) and (b) .....Yes.

§63.16 ................Yes.
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Subpart HHH–-[AMENDED]

23. Section 63.1270 is amended by:

a. Revising paragraph (a) introductory text;

b. Revising paragraph (a)(4);

c. Revising paragraphs (d)(1) and (d)(2); and 

d. Adding paragraphs (d)(3),(4) and (5) to read as 

follows:

§63.1270 Applicability and designation of affected source.

(a) This subpart applies to owners and operators of 

natural gas transmission and storage facilities that 

transport or store natural gas prior to entering the 

pipeline to a local distribution company or to a final end 

user (if there is no local distribution company), and that 

are major sources of hazardous air pollutants (HAP) 

emissions as defined in §63.1271. Emissions for major 

source determination purposes can be estimated using the 

maximum natural gas throughput calculated in either 

paragraph (a)(1) or (2) of this section and paragraphs 

(a)(3) and (4) of this section. As an alternative to 

calculating the maximum natural gas throughput, the owner 

or operator of a new or existing source may use the 

facility design maximum natural gas throughput to estimate 
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the maximum potential emissions. Other means to determine 

the facility's major source status are allowed, provided 

the information is documented and recorded to the 

Administrator's satisfaction in accordance with 

§63.10(b)(3). A compressor station that transports natural 

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

gas processing plant (if present) is not considered a part 

of the natural gas transmission and storage source 

category. A facility that is determined to be an area 

source, but subsequently increases its emissions or its 

potential to emit above the major source levels (without 

obtaining and complying with other limitations that keep 

its potential to emit HAP below major source levels), and 

becomes a major source, must comply thereafter with all 

applicable provisions of this subpart starting on the 

applicable compliance date specified in paragraph (d) of 

this section. Nothing in this paragraph is intended to 

preclude a source from limiting its potential to emit 

through other appropriate mechanisms that may be available 

through the permitting authority.

* * * * *
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(4) The owner or operator shall determine the maximum 

values for other parameters used to calculate potential 

emissions as the maximum over the same period for which 

maximum throughput is determined as specified in paragraph 

(a)(1) or (a)(2) of this section. These parameters shall be 

based on an annual average or the highest single measured 

value. For estimating maximum potential emissions from 

glycol dehydration units, the glycol circulation rate used 

in the calculation shall be the unit’s maximum rate under 

its physical and operational design consistent with the 

definition of potential to emit in §63.2.

* * * * *

(d) * * *

(1) Except as specified in paragraphs (d)(3) through

(5) of this section, the owner or operator of an affected 

source, the construction or reconstruction of which 

commenced before February 6, 1998, shall achieve compliance 

with this provisions of the subpart no later than June 17, 

2002 except as provided for in §63.6(i). The owner or 

operator of an area source, the construction or 

reconstruction of which commenced before February 6, 1998, 

that increases its emissions of (or its potential to emit) 
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HAP such that the source becomes a major source that is 

subject to this subpart shall comply with this subpart 3 

years after becoming a major source.

(2) Except as specified in paragraphs (d)(3) through

(5) of this section, the owner or operator of an affected 

source, the construction or reconstruction of which 

commences on or after February 6, 1998, shall achieve 

compliance with the provisions of this subpart immediately 

upon initial startup or June 17, 1999, whichever date is 

later. Area sources, the construction or reconstruction of 

which commences on or after February 6, 1998, that become 

major sources shall comply with the provisions of this 

standard immediately upon becoming a major source.

(3) Each affected small glycol dehydration unit, as 

defined in §63.1271, located at a major source, that 

commenced construction before [INSERT DATE OF PUBLICATION 

IN THE FEDERAL REGISTER] must achieve compliance no later 

than 3 years after the date of publication of the final 

rule in the Federal Register, except as provided in 

§63.6(i).

(4) Each affected small glycol dehydration unit, as 

defined in §63.1271, located at a major source, that 
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commenced construction on or after [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER] must achieve 

compliance immediately upon initial startup or the date of 

publication of the final rule in the Federal Register, 

whichever is later.

(5) Each large glycol dehydration unit, as defined in 

§63.1271, that has complied with the provisions of this 

subpart prior to [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER] by reducing its benzene emissions to less than 

0.9 megagrams per year must achieve compliance no later 

than 90 days after the date of publication of the final 

rule in the Federal Register, except as provided in 

§63.6(i).

* * * * *

24. Section 63.1271 is amended by:

a. Adding, in alphabetical order, new definitions for

the terms “affirmative defense,” “BTEX,” “flare,” “large 

glycol dehydration units,” “small glycol dehydration 

units”; and 

b. Revising, in alphabetical order, the definition for 

“glycol dehydration unit baseline operations” and

“temperature monitoring device” to read as follows:
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§63.1271 Definitions.

* * * * *

Affirmative defense means, in the context of an 

enforcement proceeding, a response or defense put forward 

by a defendant, regarding which the defendant has the 

burden of proof, and the merits of which are independently 

and objectively evaluated in a judicial or administrative 

proceeding.

* * * * *

BTEX means benzene, toluene, ethyl benzene and xylene.

* * * * *

Flare means a thermal oxidation system using an open 

flame (i.e., without enclosure). 

* * * * *

Glycol dehydration unit baseline operations means 

operations representative of the large glycol dehydration 

unit operations as of June 17, 1999 and the small glycol 

dehydration unit operations as of [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. For the purposes of 

this subpart, for determining the percentage of overall HAP 

emission reduction attributable to process modifications, 

glycol dehydration unit baseline operations shall be 
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parameter values (including, but not limited to, glycol 

circulation rate or glycol-HAP absorbency) that represent 

actual long-term conditions (i.e., at least 1 year). Glycol 

dehydration units in operation for less than 1 year shall 

document that the parameter values represent expected longterm operating conditions had process modifications not 

been made.

* * * * *

Large glycol dehydration unit means a glycol 

dehydration unit with an actual annual average natural gas 

flowrate equal to or greater than 283.0 thousand standard 

cubic meters per day and actual annual average benzene 

emissions equal to or greater than 0.90 Mg/yr, determined 

according to §63.1282(a).

* * * * * 

Small glycol dehydration unit means a glycol 

dehydration unit, located at a major source, with an actual 

annual average natural gas flowrate less than 283.0 

thousand standard cubic meters per day or actual annual 

average benzene emissions less than 0.90 Mg/yr, determined 

according to §63.1282(a).
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Temperature monitoring device means an instrument used 

to monitor temperature and having a minimum accuracy of ±1 

percent of the temperature being monitored expressed in °C, 

or ±2.5 °C, whichever is greater. The temperature 

monitoring device may measure temperature in degrees 

Fahrenheit or degrees Celsius, or both.

25. Section 63.1272 is amended by:

a. Revising paragraph (a) through (d); and

b. Deleting paragraph (e) to read as follows:

§63.1272 Startups and shutdowns.

(a) The provisions set forth in this subpart shall 

apply at all times.

(b) The owner or operator shall not shut down items of 

equipment that are required or utilized for compliance with 

the provisions of this subpart during times when emissions 

are being routed to such items of equipment, if the 

shutdown would contravene requirements of this subpart 

applicable to such items of equipment. This paragraph does 

not apply if the owner or operator must shut down the 

equipment to avoid damage due to a contemporaneous startup 

or shutdown of the affected source or a portion thereof.
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(c) During startups and shutdowns, the owner or 

operator shall implement measures to prevent or minimize 

excess emissions to the maximum extent practical. 

(d) In response to an action to enforce the standards 

set forth in this subpart, you may assert an affirmative 

defense to a claim for civil penalties for exceedances of 

such standards that are caused by malfunction, as defined 

in §63.2. Appropriate penalties may be assessed, however, 

if you fail to meet your burden of proving all the 

requirements in the affirmative defense. The affirmative 

defense shall not be available for claims for injunctive 

relief.

(1) To establish the affirmative defense in any action 

to enforce such a limit, the owner or operator must timely 

meet the notification requirements in paragraph (d)(2) of 

this section, and must prove by a preponderance of evidence 

that:

(i) The excess emissions:

(A) Were caused by a sudden, infrequent, and 

unavoidable failure of air pollution control and monitoring 

equipment, process equipment, or a process to operate in a 

normal or usual manner; and 
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(B) Could not have been prevented through careful 

planning, proper design or better operation and maintenance 

practices; and

(C) Did not stem from any activity or event that could 

have been foreseen and avoided, or planned for; and 

(D) Were not part of a recurring pattern indicative of 

inadequate design, operation, or maintenance; and 

(ii) Repairs were made as expeditiously as possible 

when the applicable emission limitations were being 

exceeded. Off-shift and overtime labor were used, to the 

extent practicable to make these repairs; and 

(iii) The frequency, amount and duration of the excess 

emissions (including any bypass) were minimized to the 

maximum extent practicable during periods of such 

emissions; and 

(iv) If the excess emissions resulted from a bypass of 

control equipment or a process, then the bypass was 

unavoidable to prevent loss of life, personal injury, or 

severe property damage; and 

(v) All possible steps were taken to minimize the 

impact of the excess emissions on ambient air quality, the 

environment, and human health; and 
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(vi) All emissions monitoring and control systems were 

kept in operation if at all possible, consistent with 

safety and good air pollution control practices; and 

(vii) All of the actions in response to the excess 

emissions were documented by properly signed, 

contemporaneous operating logs; and 

(viii) At all times, the affected source was operated 

in a manner consistent with good practices for minimizing 

emissions; and 

(ix) A written root cause analysis has been prepared 

to determine, correct, and eliminate the primary causes of 

the malfunction and the excess emissions resulting from the 

malfunction event at issue. The analysis shall also 

specify, using best monitoring methods and engineering 

judgment, the amount of excess emissions that were the 

result of the malfunction.

(2) Notification. The owner or operator of the 

affected source experiencing an exceedance of its emission 

limit(s) during a malfunction shall notify the 

Administrator by telephone or facsimile transmission as 

soon as possible, but no later than two business days after 

the initial occurrence of the malfunction, if it wishes to 
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avail itself of an affirmative defense to civil penalties 

for that malfunction. The owner or operator seeking to 

assert an affirmative defense shall also submit a written 

report to the Administrator within 45 days of the initial 

occurrence of the exceedance of the standard in this 

subpart to demonstrate, with all necessary supporting 

documentation, that it has met the requirements set forth 

in paragraph (d)(1) of this section. The owner or operator 

may seek an extension of this deadline for up to 30 

additional days by submitting a written request to the 

Administrator before the expiration of the 45 day period. 

Until a request for an extension has been approved by the 

Administrator, the owner or operator is subject to the 

requirement to submit such report within 45 days of the 

initial occurrence of the exceedance. 

* * * * *

26. Section 63.1274 is amended by:

a. Revising paragraph (c) introductory text;

b. Deleting and reserving paragraph (d);

c. Revising paragraph (g); and

d. Adding paragraph (h) to read as follows:
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§63.1274 General standards.

* * * * *

(c) The owner or operator of an affected source (i.e., 

glycol dehydration unit) located at an existing or new 

major source of HAP emissions shall comply with the 

requirements in this subpart as follows:

* * * * *

(d) [Reserved]

* * * * *

(g) In all cases where the provisions of this subpart 

require an owner or operator to repair leaks by a specified 

time after the leak is detected, it is a violation of this 

standard to fail to take action to repair the leak(s) 

within the specified time. If action is taken to repair the 

leak(s) within the specified time, failure of that action 

to successfully repair the leak(s) is not a violation of 

this standard. However, if the repairs are unsuccessful, 

and a leak is detected, the owner or operator shall take 

further action as required by the applicable provisions of 

this subpart.

(h) At all times the owner or operator must operate 

and maintain any affected source, including associated air 
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pollution control equipment and monitoring equipment, in a 

manner consistent with safety and good air pollution 

control practices for minimizing emissions. Determination 

of whether such operation and maintenance procedures are 

being used will be based on information available to the 

Administrator which may include, but is not limited to, 

monitoring results, review of operation and maintenance 

procedures, review of operation and maintenance records, 

and inspection of the source.

27. Section 63.1275 is amended by:

a. Revising paragraph (a);

b. Revising paragraph (b)(1) introductory text;

c. Revising paragraph (b)(1)(i);

d. Deleting and reserving paragraph (b)(1)(ii);

e. Adding paragraph (b)(1)(iii);

f. Revising paragraph (c)(2);

g. Revising paragraph (c)(3) introductory text;

h. Revising paragraph (c)(1)(i);

i. Deleting and reserving paragraph (c)(3)(ii); and

j. Adding paragraph (c)(3)(iii) to read as follows:
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§63.1275 Glycol dehydration unit process vent standards.

(a) This section applies to each glycol dehydration 

unit subject to this subpart that must be controlled for 

air emissions as specified in paragraph (c)(1) of §63.1274.

(b) * * *

(1) For each glycol dehydration unit process vent, the 

owner or operator shall control air emissions by either 

paragraph (b)(1)(i) or (b)(1)(iii) of this section.

(i) The owner or operator of a large glycol 

dehydration unit, as defined in §63.1271, shall connect the 

process vent to a control device or a combination of 

control devices through a closed-vent system. The closedvent system shall be designed and operated in accordance 

with the requirements of §63.1281(c). The control device(s) 

shall be designed and operated in accordance with the 

requirements of §63.1281(d).

(ii) [Reserved]

(iii) You must limit BTEX emissions from each small 

glycol dehydration unit, as defined in §63.1271, to the 

limit determined in Equation 1 of this section. The limit 

must be met in accordance with one of the alternatives 
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specified in paragraphs (b)(i)(iii)(A) through (D) of this 

section. 

Equation 1

Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per 

year;

6.42x10-5 = BTEX emission limit, grams BTEX/standard cubic 

meter -ppmv;

Throughput = Annual average daily natural gas throughput, 

standard cubic meters per day

Ci,BTEX = BTEX concentration of the natural gas at the inlet 

to the glycol dehydration unit, ppmv.

(A) Connect the process vent to a control device or 

combination of control devic

system. The closed vent system shall be designed and 

operated in accordance with the requirements of 

§63.1281(c). The control device(s) shall be designed and 

operated in accordance with the requirements of 

§63.1281(f).

(B) Meet the emissions limit through process 

modifications in accordance with the requirements specified 

in §63.1281(e).

(C) Meet the emission limit for each small glycol 

dehydration unit using a combination of process 

modifications and one or more control devices t

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specified in paragraphs (b)(i)(iii)(A) through (D) of this 

 

specific BTEX emission limit, megagrams per 

= BTEX emission limit, grams BTEX/standard cubic 

Annual average daily natural gas throughput, 

standard cubic meters per day

= BTEX concentration of the natural gas at the inlet 

to the glycol dehydration unit, ppmv.

(A) Connect the process vent to a control device or 

combination of control devices through a closed-vent 

The closed vent system shall be designed and 

operated in accordance with the requirements of 

The control device(s) shall be designed and 

operated in accordance with the requirements of 

e emissions limit through process 

modifications in accordance with the requirements specified 

(C) Meet the emission limit for each small glycol 

dehydration unit using a combination of process 

modifications and one or more control devices through the 

Do Not Cite, 

specified in paragraphs (b)(i)(iii)(A) through (D) of this 

 

specific BTEX emission limit, megagrams per 

= BTEX emission limit, grams BTEX/standard cubic 

Annual average daily natural gas throughput, 

= BTEX concentration of the natural gas at the inlet 

(A) Connect the process vent to a control device or 

vent 

The closed vent system shall be designed and 

The control device(s) shall be designed and 

modifications in accordance with the requirements specified 

(C) Meet the emission limit for each small glycol 

hrough the 
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requirements specified in paragraphs (b)(1)(iii)(A) and (B) 

of this section.

(D) Demonstrate that the emissions limit is met 

through actual uncontrolled operation of the small glycol 

dehydration unit. Document operational parameters in 

accordance with the requirements specified in §63.1281(e) 

and emissions in accordance with the requirements specified 

in §63.1282(a)(3).

* * * * *

(c) * * *

(2) The owner or operator shall demonstrate, to the 

Administrator's satisfaction, that the total HAP emissions 

to the atmosphere from the large glycol dehydration unit 

process vent are reduced by 95.0 percent through process 

modifications or a combination of process modifications and 

one or more control devices, in accordance with the 

requirements specified in §63.1281(e).

(3) Control of HAP emissions from a GCG separator 

(flash tank) vent is not required if the owner or operator 

demonstrates, to the Administrator's satisfaction, that 

total emissions to the atmosphere from the glycol 

dehydration unit process vent are reduced by one of the 
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levels specified in paragraph (c)(3)(i) or (iii) through 

the installation and operation of controls as specified in 

paragraph (b)(1) of this section.

(i) For any large glycol dehydration unit, HAP 

emissions are reduced by 95.0 percent or more.

(ii) [Reserved] 

(iii) For each small glycol dehydration unit, BTEX 

emissions are reduced to a level less than the limit 

calculated in paragraph (b)(1)(iii) of this section.

28. Section 63.1281 is amended by:

a. Revising paragraph (c)(1);

b. Revising paragraph (d)(1) introductory text;

c. Revising paragraph (d)(1)(i);

d. Revising paragraph (d)(1)(i)(C);

e. Revising paragraphs (d)(1)(ii) and (iii);

f. Revising paragraph (d)(4)(i);

g. Revising paragraph (d)(5)(i);

h. Revising paragraph (e)(2);

i. Revising paragraph (e)(3) introductory text;

j. Revising paragraph (e)(3)(ii); and

k. Adding paragraph (f) to read as follows:
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§63.1281 Control equipment requirements.

* * * * *

(c) * * *

(1) The closed-vent system shall route all gases, 

vapors, and fumes emitted from the material in an emissions 

unit to a control device that meets the requirements 

specified in paragraph (d) of this section.

* * * * *

(d) Control device requirements for sources except 

small glycol dehydration units. Owners and operators of 

small glycol dehydration units shall comply with the 

control requirements in paragraph (f) of this section.

(1) * * *

(i) An enclosed combustion device (e.g., thermal vapor 

incinerator, catalytic vapor incinerator, boiler, or 

process heater) that is designed and operated in accordance 

with one of the following performance requirements:

* * * * *

(C) For a control device that can demonstrate a 

uniform combustion zone temperature during the performance 

test conducted under §63.1282(d), operates at a minimum 

temperature of 760°C.
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* * * * *

(ii) A vapor recovery device (e.g., carbon adsorption 

system or condenser) or other non-destructive control 

device that is designed and operated to reduce the mass 

content of either TOC or total HAP in the gases vented to 

the device by 95.0 percent by weight or greater as 

determined in accordance with the requirements of 

§63.1282(d).

(iii) A flare, as defined in §63.1271, that is 

designed and operated in accordance with the requirements 

of §63.11(b).

* * * * *

(4) * * * 

(i) Each control device used to comply with this 

subpart shall be operating at all times when gases, vapors, 

and fumes are vented from the emissions unit or units 

through the closed vent system to the control device as 

required under §63.1275. An owner or operator may vent more 

than one unit to a control device used to comply with this 

subpart.

(5) * * *
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(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. Records identifying the 

schedule for replacement and records of each carbon 

replacement shall be maintained as required in 

§63.1284(b)(7)(ix). The schedule for replacement shall be 

submitted with the Notification of Compliance Status Report 

as specified in §63.1285(d)(4)(iv). Each carbon replacement 

must be reported in the Periodic Reports as specified in 

§63.1285(e)(2)(xi).

* * * * *

(e) * * *

* * * * *

(2) The owner or operator shall document, to the 

Administrator's satisfaction, the conditions for which 

glycol dehydration unit baseline operations shall be 

modified to achieve the 95.0 percent overall HAP emission 

reduction, or BTEX limit determined in §63.1275(b)(1)(iii), 

as applicable, either through process modifications or 

through a combination of process modifications and one or 
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more control devices. If a combination of process 

modifications and one or more control devices are used, the 

owner or operator shall also establish the emission 

reduction to be achieved by the control device to achieve 

an overall HAP emission reduction of 95.0 percent for the 

glycol dehydration unit process vent or, if applicable, the 

BTEX limit determined in §63.1275(b)(1)(iii) for the small 

glycol dehydration unit process vent. Only modifications in 

glycol dehydration unit operations directly related to 

process changes, including but not limited to changes in 

glycol circulation rate or glycol-HAP absorbency, shall be 

allowed. Changes in the inlet gas characteristics or 

natural gas throughput rate shall not be considered in 

determining the overall emission reduction due to process 

modifications.

(3) The owner or operator that achieves a 95.0 percent 

HAP emission reduction or meets the BTEX limit determined 

in §63.1275(b)(1)(iii), as applicable, using process 

modifications alone shall comply with paragraph (e)(3)(i) 

of this section. The owner or operator that achieves a 95.0 

percent HAP emission reduction or meets the BTEX limit 

determined in §63.1275(b)(1)(iii), as applicable, using a 
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combination of process modifications and one or more 

control devices shall comply with paragraphs (e)(3)(i) and 

(e)(3)(ii) of this section.

* * * * *

(ii) The owner or operator shall comply with the 

control device requirements specified in paragraph (d) or 

(f) of this section, as applicable, except that the 

emission reduction or limit achieved shall be the emission 

reduction or limit specified for the control device(s) in 

paragraph (e)(2) of this section.

(f) Control device requirements for small glycol 

dehydration units.

(1) The control device used to meet BTEX the emission 

limit calculated in §63.1275(b)(1)(iii) shall be one of the 

control devices specified in paragraphs (f)(1)(i) through 

(iii) of this section.

(i) An enclosed combustion device (e.g., thermal vapor 

incinerator, catalytic vapor incinerator, boiler, or 

process heater) that is designed and operated to reduce the 

mass content of BTEX in the gases vented to the device as 

determined in accordance with the requirements of 

§63.1282(d). If a boiler or process heater is used as the 
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control device, then the vent stream shall be introduced 

into the flame zone of the boiler or process heater; or

(ii) A vapor recovery device (e.g., carbon adsorption 

system or condenser) or other non-destructive control 

device that is designed and operated to reduce the mass 

content of BTEX in the gases vented to the device as 

determined in accordance with the requirements of 

§63.1282(d); or

(iii) A flare, as defined in §63.1271, that is 

designed and operated in accordance with the requirements 

of §63.11(b). 

(2) The owner or operator shall operate each control 

device in accordance with the requirements specified in 

paragraphs (f)(2)(i) and (ii) of this section.

(i) Each control device used to comply with this 

subpart shall be operating at all times. An owner or 

operator may vent more than one unit to a control device 

used to comply with this subpart.

(ii) For each control device monitored in accordance 

with the requirements of §63.1283(d), the owner or operator 

shall demonstrate compliance according to the requirements 

of either §63.1282(e) or (h).
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(3) For each carbon adsorption system used as a 

control device to meet the requirements of paragraph (f)(1) 

of this section, the owner or operator shall manage the 

carbon as required under (d)(5)(i) and (ii) of this 

section.

29. Section 63.1282 is amended by:

a. Revising paragraph (a) introductory text;

b. Revising paragraph (a)(1)(ii);

c. Revising paragraph (a)(2) introductory text;

d. Revising paragraphs (a)(2)(i) and (ii);

e. Adding paragraph (c);

f. Revising paragraph (d) introductory text;

g. Revising paragraphs (d)(1)(i) through (v);

h. Revising paragraph (d)(2);

i. Revising paragraph (d)(3) introductory text;

j. Revising paragraph (d)(3)(i)(B);

k. Revising paragraph (d)(3)(iv)(C)(1)

l. Adding paragraphs (d)(3)(v) and (vi);

m. Revising paragraph (d)(4) introductory text;

n. Revising paragraph (d)(4)(i);

o. Revising paragraph (d)(5);

p. Revising paragraph (e) introductory text;
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q. Adding paragraphs (e)(2) through (e)(6);

r. Revising paragraph (f) introductory text;

s. Revising paragraph (f)(1);

t. Revising paragraph (f)(2) introductory text;

u. Revising paragraph (f)(2)(iii);

v. Revising paragraph (f)(3); and

w. Adding paragraphs (g) and (h) to read as follows:

§63.1282 Test methods, compliance procedures, and 

compliance demonstrations.

(a) Determination of glycol dehydration unit flowrate, 

benzene emissions, or BTEX emissions. The procedures of 

this paragraph shall be used by an owner or operator to 

determine glycol dehydration unit natural gas flowrate, 

benzene emissions, or BTEX emissions.

(1) * * *

* * * * *

(ii) The owner or operator shall document, to the 

Administrator's satisfaction, the actual annual average 

natural gas flowrate to the glycol dehydration unit.

(2) The determination of actual average benzene or 

BTEX emissions from a glycol dehydration unit shall be made 

using the procedures of either paragraph (a)(2)(i) or 
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(a)(2)(ii) of this section. Emissions shall be determined 

either uncontrolled or with federally enforceable controls 

in place.

(i) The owner or operator shall determine actual 

average benzene or BTEX emissions using the model GRIGLYCalcTM, Version 3.0 or higher, and the procedures 

presented in the associated GRI-GLYCalcTM Technical 

Reference Manual. Inputs to the model shall be 

representative of actual operating conditions of the glycol 

dehydration unit and may be determined using the procedures 

documented in the Gas Research Institute (GRI) report 

entitled “Atmospheric Rich/Lean Method for Determining 

Glycol Dehydrator Emissions” (GRI–95/0368.1); or

(ii) The owner or operator shall determine an average 

mass rate of benzene or BTEX emissions in kilograms per 

hour through direct measurement by performing three runs of 

Method 18 in 40 CFR part 60, appendix A (or an equivalent 

method), and averaging the results of the three runs. 

Annual emissions in kilograms per year shall be determined 

by multiplying the mass rate by the number of hours the 

unit is operated per year. This result shall be converted 

to megagrams per year.
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* * * * * (c) Test procedures and compliance 

demonstrations for small glycol dehydration units. This 

paragraph applies to the test procedures for small 

dehydration units.

(1) If the owner or operator is using a control 

device to comply with the emission limit in 

§63.1275(b)(1)(iii), the requirements of paragraph (d) of 

this section apply. Compliance is demonstrated using the 

methods specified in paragraph (e) of this section.

(2) If no control device is used to comply with the 

emission limit in §63.1275(b)(1)(iii), the owner or 

operator must determine the glycol dehydration unit BTEX 

emissions as specified in paragraphs (c)(2)(i) through 

(iii) of this section. Compliance is demonstrated if the 

BTEX emissions determined as specified in paragraphs 

(c)(2)(i) through (iii) are less than the emission limit 

calculated using the equation in §63.1275(b)(1)(iii).

(i) Method 1 or 1A, 40 CFR part 60, appendix A, as 

appropriate, shall be used for selection of the sampling 

sites at the outlet of the glycol dehydration unit process 

vent. Any references to particulate mentioned in Methods 1 

and 1A do not apply to this section.
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(ii) The gas volumetric flowrate shall be determined 

using Method 2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, 

as appropriate.

(iii) The BTEX emissions from the outlet of the 

glycol dehydration unit process vent shall be determined 

using the procedures specified in paragraph (d)(3)(v) of 

this section. As an alternative, the mass rate of BTEX at 

the outlet of the glycol dehydration unit process vent may 

be calculated using the model GRI-GLYCalcTM , Version 3.0 or 

higher, and the procedures presented in the associated GRIGLYCalcTM Technical Reference Manual. Inputs to the model 

shall be representative of actual operating conditions of 

the glycol dehydration unit and shall be determined using 

the procedures documented in the Gas Research Institute 

(GRI) report entitled “Atmospheric Rich/Lean Method for 

Determining Glycol Dehydrator Emissions” (GRI–95/0368.1). 

When the BTEX mass rate is calculated for glycol 

dehydration units using the model GRI-GLYCalcTM, all BTEX 

measured by Method 18, 40 CFR part 60, appendix A, shall be 

summed.

(d) Control device performance test procedures. This 

paragraph applies to the performance testing of control 
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devices. The owners or operators shall demonstrate that a 

control device achieves the performance requirements of 

§63.1281(d)(1), (e)(3)(ii), or (f)(1) using a performance 

test as specified in paragraph (d)(3) of this section. 

Owners or operators using a condenser have the option to 

use a design analysis as specified in paragraph (d)(4) of 

this section. The owner or operator may elect to use the 

alternative procedures in paragraph (d)(5) of this section 

for performance testing of a condenser used to control 

emissions from a glycol dehydration unit process vent. As 

an alternative to conducting a performance test under this 

section for combustion control devices, a control device 

that can be demonstrated to meet the performance 

requirements of §63.1281(d)(1), (e)(3)(ii), or (f)(1)

through a performance test conducted by the manufacturer, 

as specified in paragraph (g) of this section, can be used.

(1) * * *

(i) Except as specified in paragraph (d)(2) of this 

section, a flare, as defined in §63.1271, that is designed 

and operated in accordance with §63.11(b);
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(ii) Except for control devices used for small glycol 

dehydration units, a boiler or process heater with a design 

heat input capacity of 44 megawatts or greater;

(iii) Except for control devices used for small glycol 

dehydration units, a boiler or process heater into which 

the vent stream is introduced with the primary fuel or is 

used as the primary fuel;

(iv) Except for control devices used for small glycol 

dehydration units, a boiler or process heater burning 

hazardous waste for which the owner or operator has either 

been issued a final permit under 40 CFR part 270 and 

complies with the requirements of 40 CFR part 266, subpart 

H, or has certified compliance with the interim status 

requirements of 40 CFR part 266, subpart H;

(v) Except for control devices used for small glycol 

dehydration units, a hazardous waste incinerator for which 

the owner or operator has been issued a final permit under 

40 CFR part 270 and complies with the requirements of 40 

CFR part 264, subpart O, or has certified compliance with 

the interim status requirements of 40 CFR part 265, subpart 

O.

* * * * *
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(2) An owner or operator shall design and operate each 

flare, as defined in §63.1271, in accordance with the

requirements specified in §63.11(b) and the compliance 

determination shall be conducted using Method 22 of 40 CFR 

part 60, appendix A, to determine visible emissions.

(3) For a performance test conducted to demonstrate 

that a control device meets the requirements of 

§63.1281(d)(1), (e)(3)(ii), or (f)(1) the owner or operator 

shall use the test methods and procedures specified in 

paragraphs (d)(3)(i) through (v) of this section. The 

initial and periodic performance tests shall be conducted 

according to the schedule specified in paragraph (d)(3)(vi) 

of this section.

(i) * * *

* * * * *

(B) To determine compliance with the enclosed 

combustion device total HAP concentration limit specified 

in §63.1281(d)(1)(i)(B), or the BTEX emission limit 

specified in §63.1275(b)(1)(iii), the sampling site shall 

be located at the outlet of the combustion device.

* * * * *

(iv) * * *
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* * * * *

(C) * * *

* * * * *

(1) The emission rate correction factor for excess 

air, integrated sampling and analysis procedures of Method

3A or 3B, 40 CFR part 60, appendix A, shall be used to 

determine the oxygen concentration (%O2d). The samples shall 

be taken during the same time that the samples are taken 

for determining TOC concentration or total HAP 

concentration.

* * * * *

(v) To determine compliance with the BTEX emission 

limit specified in §63.1281(f)(1) the owner or operator 

shall use one of the following methods: Method 18, 40 CFR 

part 60, appendix A; ASTM D6420–99 (2004), as specified in 

§63.772(a)(1)(ii); or any other method or data that have 

been validated according to the applicable procedures in 

Method 301, 40 CFR part 63, appendix A. The following 

procedures shall be used to calculate BTEX emissions:

(A) The minimum sampling time for each run shall be 1 

hour in which either an integrated sample or a minimum of 

four grab samples shall be taken. If grab sampling is used, 
*** E.O. 12866 Review 

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then the samples shall be taken at approximately equal 

intervals in time, such as 15

run.

(B) The mass rate of BTEX (E

the equations and procedures specified in paragraphs 

(d)(3)(v)(B)(1) and (

(1) The following equation shall be used:

Where:

Eo= Mass rate of BTEX at the outlet of the control device, 

dry basis, kilogram per hour.

Coj= Concentration of sample component j of the gas stream 

at the outlet of the control device, dry basis, parts per 

million by volume.

Moj= Molecular weight of sample component j of the gas 

stream at the outlet of the control device, gram/gram

Qo= Flowrate of gas stream at the outlet of the control 

device, dry standard cubic meter per minute.

K2= Constant, 2.494×10

standard cubic meter) (kilogram/gram) (minute/hour), where 

standard temperature (gram

is 20 degrees C.

n = Number of components in sample.

(2) When the BTEX mass rate is calculated, only BTEX 

compounds measured by Method 18, 40 CFR part 60, appendix 

A, or ASTM D6420–99 (2004)

§63.772(a)(1)(ii), shall be summe

paragraph (d)(3)(v)(B)(

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then the samples shall be taken at approximately equal 

intervals in time, such as 15-minute intervals during the 

(B) The mass rate of BTEX (Eo) shall be computed using 

the equations and procedures specified in paragraphs 

) and (2) of this section. 

) The following equation shall be used:

= Mass rate of BTEX at the outlet of the control device, 

dry basis, kilogram per hour.

= Concentration of sample component j of the gas stream 

at the outlet of the control device, dry basis, parts per 

= Molecular weight of sample component j of the gas 

stream at the outlet of the control device, gram/gram

rate of gas stream at the outlet of the control 

device, dry standard cubic meter per minute.

= Constant, 2.494×10−6 (parts per million) (gram-mole per 

standard cubic meter) (kilogram/gram) (minute/hour), where 

standard temperature (gram-mole per standard cubic meter) 

n = Number of components in sample.

) When the BTEX mass rate is calculated, only BTEX 

compounds measured by Method 18, 40 CFR part 60, appendix 

99 (2004) as specified in 

, shall be summed using the equations in 

paragraph (d)(3)(v)(B)(1) of this section.

Do Not Cite, 

then the samples shall be taken at approximately equal 

minute intervals during the 

e computed using 

the equations and procedures specified in paragraphs 

= Mass rate of BTEX at the outlet of the control device, 

= Concentration of sample component j of the gas stream 

at the outlet of the control device, dry basis, parts per 

= Molecular weight of sample component j of the gas 

stream at the outlet of the control device, gram/gram-mole.

rate of gas stream at the outlet of the control 

mole per 

standard cubic meter) (kilogram/gram) (minute/hour), where 

cubic meter) 

) When the BTEX mass rate is calculated, only BTEX 

compounds measured by Method 18, 40 CFR part 60, appendix 

d using the equations in 
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(vi) The owner or operator shall conduct performance 

tests according to the schedule specified in paragraphs 

(d)(3)(vi)(A) and (B) of this section.

(A) An initial performance test shall be conducted 

within 180 days after the compliance date that is specified 

for each affected source in §63.1270(d)(3) and (4) except 

that the initial performance test for existing combustion 

control devices at existing major sources shall be 

conducted no later than 3 years after the date of 

publication of the final rule in the Federal Register. If 

the owner or operator of an existing combustion control 

device at an existing major source chooses to replace such 

device with a control device whose model is tested under 

§63.1282(g), then the newly installed device shall comply 

with all provisions of this subpart no later than 3 years 

after the date of publication of the final rule in the 

Federal Register. The performance test results shall be 

submitted in the Notification of Compliance Status Report 

as required in §63.1285(d)(1)(ii).

(B) Periodic performance tests shall be conducted for 

all control devices required to conduct initial performance 

tests except as specified in paragraphs (e)(3)(vi)(B)(1) 
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and (2) of this section. The first periodic performance 

test shall be conducted no later than 60 months after the 

initial performance test required in paragraph 

(d)(3)(vi)(A) of this section. Subsequent periodic

performance tests shall be conducted at intervals no longer 

than 60 months following the previous periodic performance 

test or whenever a source desires to establish a new 

operating limit. The periodic performance test results must 

be submitted in the next Periodic Report as specified in 

§63.1285(e)(2)(x). Combustion control devices meeting the 

criteria in either paragraph (e)(3)(vi)(B)(1) or (2) of 

this section are not required to conduct periodic 

performance tests.

(1) A control device whose model is tested under, and 

meets the criteria of, §63.1282(g), or

(2) A combustion control device tested under 

§63.1282(d) that meets the outlet TOC or HAP performance 

level specified in §63.1281(d)(1)(i)(B) and that 

establishes a correlation between firebox or combustion 

chamber temperature and the TOC or HAP performance level.

* * * * *
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(4) For a condenser design analysis conducted to meet 

the requirements of §63.1281(d)(1), (e)(3)(ii), or (f)(1), 

the owner or operator shall meet the requirements specified 

in paragraphs (d)(4)(i) and (d)(4)(ii) of this section. 

Documentation of the design analysis shall be submitted as 

a part of the Notification of Compliance Status Report as 

required in §63.1285(d)(1)(i).

(i) The condenser design analysis shall include an 

analysis of the vent stream composition, constituent 

concentrations, flowrate, relative humidity, and 

temperature, and shall establish the design outlet organic 

compound concentration level, design average temperature of 

the condenser exhaust vent stream, and the design average 

temperatures of the coolant fluid at the condenser inlet 

and outlet. As an alternative to the condenser design 

analysis, an owner or operator may elect to use the 

procedures specified in paragraph (d)(5) of this section.

* * * * *

(5) As an alternative to the procedures in paragraph 

(d)(4)(i) of this section, an owner or operator may elect 

to use the procedures documented in the GRI report 

entitled, “Atmospheric Rich/Lean Method for Determining 
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Glycol Dehydrator Emissions,” (GRI–95/0368.1) as inputs for 

the model GRI-GLYCalcTM, Version 3.0 or higher, to generate 

a condenser performance curve.

(e) Compliance demonstration for control devices 

performance requirements. This paragraph applies to the 

demonstration of compliance with the control device 

performance requirements specified in §63.1281(d)(1), 

(e)(3)(ii), and (f)(1). Compliance shall be demonstrated 

using the requirements in paragraphs (e)(1) through (3) of 

this section. As an alternative, an owner or operator that 

installs a condenser as the control device to achieve the 

requirements specified in §63.1281(d)(1)(ii), (e)(3)(ii), 

or (f)(1) may demonstrate compliance according to paragraph 

(f) of this section. An owner or operator may switch 

between compliance with paragraph (e) of this section and 

compliance with paragraph (f) of this section only after at 

least 1 year of operation in compliance with the selected 

approach. Notification of such a change in the compliance 

method shall be reported in the next Periodic Report, as 

required in §63.1285(e), following the change.

* * * * *

(2) The owner or operator shall calculate the daily 
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average of the applicable monitored parameter in accordance 

with §63.1283(d)(4) Except that the inlet gas flowrate to 

the control device shall not be averaged.

(3) Compliance is achieved when the daily average of 

the monitoring parameter value calculated under paragraph 

(e)(2) of this section is either equal to or greater than 

the minimum or equal to or less than the maximum monitoring 

value established under paragraph (e)(1) of this section. 

For inlet gas flowrate, compliance with the operating 

parameter limit is achieved when the value is equal to or 

less than the value established under §63.1282(g).

(4) Except for periods of monitoring system 

malfunctions, repairs associated with monitoring system 

malfunctions, and required monitoring system quality 

assurance or quality control activities (including, as 

applicable, system accuracy audits and required zero and 

span adjustments), the CMS required in §63.1283(d) must be 

operated at all times the affected source is operating. A 

monitoring system malfunction is any sudden, infrequent, 

not reasonably preventable failure of the monitoring system 

to provide valid data. Monitoring system failures that are 

caused in part by poor maintenance or careless operation
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are not malfunctions. Monitoring system repairs are 

required to be completed in response to monitoring system 

malfunctions and to return the monitoring system to 

operation as expeditiously as practicable.

(5) Data recorded during monitoring system 

malfunctions, repairs associated with monitoring system 

malfunctions, or required monitoring system quality 

assurance or control activities may not be used in 

calculations used to report emissions or operating levels. 

All the data collected during all other required data 

collection periods must be used in assessing the operation 

of the control device and associated control system. 

(6) Except for periods of monitoring system 

malfunctions, repairs associated with monitoring system 

malfunctions, and required quality monitoring system 

quality assurance or quality control activities (including, 

as applicable, system accuracy audits and required zero and 

span adjustments), failure to collect required data is a 

deviation of the monitoring requirements.

(f) Compliance demonstration with percent reduction or 

emission limit performance requirements—condensers. This 

paragraph applies to the demonstration of compliance with 
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the performance requirements specified in 

§63.1281(d)(1)(ii), (e)(3) or (f)(1) for condensers. 

Compliance shall be demonstrated using the procedures in 

paragraphs (f)(1) through (f)(3) of this section.

(1) The owner or operator shall establish a sitespecific condenser performance curve according to the 

procedures specified in §63.1283(d)(5)(ii). For sources 

required to meet the BTEX limit in accordance with 

§63.1281(e) or (f)(1) the owner or operator shall identify 

the minimum percent reduction necessary to meet the BTEX 

limit.

(2) Compliance with the percent reduction requirement 

in §63.1281(d)(1)(ii), (e)(3), or (f)(1) shall be 

demonstrated by the procedures in paragraphs (f)(2)(i) 

through (iii) of this section.

* * * * *

(iii) Except as provided in paragraphs (f)(2)(iii)(A), 

(B), and (D) of this section, at the end of each operating 

day the owner or operator shall calculate the 30-day 

average HAP, or BTEX, emission reduction, as appropriate, 

from the condenser efficiencies as determined in paragraph 

(f)(2)(ii) of this section for the preceding 30 operating 
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days. If the owner or operator uses a combination of 

process modifications and a condenser in accordance with 

the requirements of §63.1281(e), the 30-day average HAP 

emission, or BTEX, emission reduction, shall be calculated 

using the emission reduction achieved through process 

modifications and the condenser efficiency as determined in 

paragraph (f)(2)(ii) of this section, both for the 

preceding 30 operating days.

(A) After the compliance date specified in 

§63.1270(d), an owner or operator of a facility that stores 

natural gas that has less than 30 days of data for 

determining the average HAP, or BTEX, emission reduction, 

as appropriate, shall calculate the cumulative average at 

the end of the withdrawal season, each season, until 30 

days of condenser operating data are accumulated. For a 

facility that does not store natural gas, the owner or 

operator that has less than 30 days of data for determining 

average HAP, or BTEX, emission reduction, as appropriate, 

shall calculate the cumulative average at the end of the 

calendar year, each year, until 30 days of condenser 

operating data are accumulated.
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(B) After the compliance date specified in 

§63.1270(d), for an owner or operator that has less than 30 

days of data for determining the average HAP, or BTEX,

emission reduction, as appropriate, compliance is achieved 

if the average HAP, or BTEX, emission reduction, as 

appropriate, calculated in paragraph (f)(2)(iii)(A) of this 

section is equal to or greater than 95.0 percent.

* * * * *

(3) Compliance is achieved based on the applicable 

criteria in paragraphs (f)(3)(i) or (ii) of this section.

(i) For sources meeting the HAP emission reduction

specified in §63.1281(d)(1)(ii) or (e)(3) if the average 

HAP emission reduction calculated in paragraph (f)(2)(iii) 

of this section is equal to or greater than 95.0 percent.

(ii) For sources required to meet the BTEX limit under 

§63.1281(e)(3) or (f)(1), compliance is achieved if the 

average BTEX emission reduction calculated in paragraph 

(f)(2)(iii) of this section is equal to or greater than the 

minimum percent reduction identified in paragraph (f)(1) of 

this section.

* * * * *

(g) Performance testing for combustion control devices 
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- manufacturers’ performance test. 

(1) This paragraph applies to the performance testing 

of a combustion control device conducted by the device 

manufacturer. The manufacturer shall demonstrate that a 

specific model of control device achieves the performance 

requirements in (g)(7) of this section by conducting a 

performance test as specified in paragraphs (g)(2) through 

(6) of this section. 

(2) Performance testing shall consist of three onehour (or longer) test runs for each of the four following 

firing rate settings making a total of 12 test runs per 

test. Propene (propylene) gas shall be used for the testing 

fuel. All fuel analyses shall be performed by an 

independent third-party laboratory (not affiliated with the 

control device manufacturer or fuel supplier).

(i) 90 - 100 percent of maximum design rate (fixed 

rate).

(ii) 70 - 100 - 70 percent (ramp up, ramp down). Begin 

the test at 70 percent of the maximum design rate. Within 

the first 5 minutes, ramp the firing rate to 100 percent of 

the maximum design rate. Hold at 100 percent for 5 minutes. 

In the 10-15 minute time range, ramp back down to 70 
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percent of the maximum design rate. Repeat three more times 

for a total of 60 minutes of sampling.

(iii) 30 - 70 - 30 percent (ramp up, ramp down). Begin 

the test at 30 percent of the maximum design rate. Within 

the first 5 minutes, ramp the firing rate to 70 percent of 

the maximum design rate. Hold at 70 percent for 5 minutes. 

In the 10-15 minute time range, ramp back down to 30 

percent of the maximum design rate. Repeat three more times 

for a total of 60 minutes of sampling.

(iv) 0 - 30 - 0 percent (ramp up, ramp down). Begin 

the test at 0 percent of the maximum design rate. Within 

the first 5 minutes, ramp the firing rate to 100 percent of 

the maximum design rate. Hold at 30 percent for 5 minutes. 

In the 10-15 minute time range, ramp back down to 0 percent 

of the maximum design rate. Repeat three more times for a 

total of 60 minutes of sampling.

(3) All models employing multiple enclosures shall be 

tested simultaneously and with all burners operational. 

Results shall be reported for the each enclosure 

individually and for the average of the emissions from all 

interconnected combustion enclosures/chambers. Control 

device operating data shall be collected continuously 
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throughout the performance test using an electronic Data 

Acquisition System and strip chart. Data shall be submitted 

with the test report in accordance with paragraph (8)(iii) 

of this section.

(4) Inlet testing shall be conducted as specified in 

paragraphs (4)(i) through (iii) of this section.

(i) The fuel flow metering system shall be located in 

accordance with Method 2A, 40 CFR part 60, appendix A-1, 

(or other approved procedure) to measure fuel flow rate at 

the control device inlet location. The fitting for filling 

fuel sample containers shall be located a minimum of 8 pipe 

diameters upstream of any inlet fuel flow monitoring meter.

(ii) Inlet flow rate shall be determined using Method 

2A, 40 CFR part 60, appendix A-1. Record the start and stop 

reading for each 60-minute THC test. Record the gas 

pressure and temperature at 5-minute intervals throughout 

each 60-minute THC test.

(iii) Inlet fuel sampling shall be conducted in 

accordance with the criteria in paragraphs (g)(4)(iii)(A) 

and (B) of this section.

(A) At the inlet fuel sampling location, securely 

connect a Silonite-coated stainless steel evacuated 
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canister fitted with a flow controller sufficient to fill 

the canister over a 1 hour period. Filling shall be 

conducted as specified in the following: 

(1) Open the canister sampling valve at the beginning 

of the total hydrocarbon (THC) test, and close the canister 

at the end of the THC test.

(2) Fill one canister for each THC test run.

(3) Label the canisters individually and record on a 

chain of custody form.

(B) Each fuel sample shall be analyzed using the 

following methods. The results shall be included in the 

test report.

(1) Hydrocarbon compounds containing between one and 

five atoms of carbon plus benzene using ASTM D1945-03.

(2) Hydrogen (H2), carbon monoxide (CO), carbon dioxide 

(CO2), nitrogen (N2), oxygen (O2) using ASTM D1945-03.

(3) Carbonyl sulfide, carbon disulfide plus mercaptans 

using ASTM D5504.

(4) Higher heating value using ASTM D3588-98 or ASTM 

D4891-89.

(5) Outlet testing shall be conducted in accordance 

with the criteria in paragraphs (g)(5)(i) through (v) of 
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this section.

(i) Sampling and flowrate measured in accordance with 

the following:

(A) The outlet sampling location shall be a minimum of 

4 equivalent stack diameters downstream from the highest 

peak flame or any other flow disturbance, and a minimum of 

one equivalent stack diameter upstream of the exit or any 

other flow disturbance. A minimum of two sample ports shall 

be used. 

(B) Flow rate shall be measured using Method 1, 40 CFR 

part 60, Appendix 1, for determining flow measurement 

traverse point location; and Method 2, 40 CFR part 60, 

Appendix 1, shall be used to measure duct velocity. If low 

flow conditions are encountered (i.e., velocity pressure 

differentials less than 0.05 inches of water) during the 

performance test, a more sensitive manometer shall be used 

to obtain an accurate flow profile.

(ii) Molecular weight shall be determined as specified 

in paragraphs (g)(4)(iii)(B), (5)(ii)(A) and (B) of this 

section.

(A) An integrated bag sample shall be collected during 

the Method 4, 40 CFR part 60, Appendix A, moisture test. 
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Analyze the bag sample using a gas chromatograph-thermal 

conductivity detector (GC-TCD) analysis meeting the 

following criteria:

(1) Collect the integrated sample throughout the 

entire test, and collect representative volumes from each 

traverse location.

(2) The sampling line shall be purged with stack gas 

before opening the valve and beginning to fill the bag.

(3) The bag contents shall be kneaded or otherwise 

vigorously mixed prior to the GC analysis.

(4) The GC-TCD calibration procedure in Method 3C, 40 

CFR part 60, Appendix A, shall be modified by using EPAAlt045 as follows: For the initial calibration, triplicate 

injections of any single concentration must agree within 5 

percent of their mean to be valid. The calibration response 

factor for a single concentration re-check must be within 

10 percent of the original calibration response factor for 

that concentration. If this criterion is not met, the 

initial calibration using at least three concentration 

levels shall be repeated.

(B) Report the molecular weight of: O2, CO2, methane 

(CH4), and N2 and include in the test report submitted under 
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§63.775(d)(iii). Moisture shall be determined using Method 

4, 40 CFR part 60, Appendix A. Traverse both ports with the 

Method 4, 40 CFR part 60, Appendix A, sampling train during 

each test run. Ambient air shall not be introduced into the 

Method 3C, 40 CFR part 60, Appendix A, integrated bag 

sample during the port change.

(iv) Carbon monoxide shall be determined using Method 

10, 40 CFR part 60, Appendix A. The test shall be run at 

the same time and with the sample points used for the EPA 

Method 25A, 40 CFR part 60, Appendix A, testing. An 

instrument range of 0-10 per million by volume-dry (ppmvd) 

shall be used.

(v) Visible emissions shall be determined using Method 

22, 40 CFR part 60, Appendix A. The test shall be performed 

continuously during each test run. A digital color 

photograph of the exhaust point, taken from the position of 

the observer and annotated with date and time, will be 

taken once per test run and the four photos included in the 

test report.

(6) Total hydrocarbons (THC) shall be determined as 

specified by the following criteria:

(i) Conduct THC sampling using Method 25A, 40 CFR part 
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60, Appendix A, except the option for locating the probe in 

the center 10 percent of the stack shall not be allowed. 

The THC probe must be traversed to 16.7 percent, 50 

percent, and 83.3 percent of the stack diameter during the 

testing.

(ii) A valid test shall consist of three Method 25A, 

40 CFR part 60, Appendix A, tests, each no less than 60 

minutes in duration.

(iii) A 0-10 parts per million by volume-wet (ppmvw) 

(as propane) measurement range is preferred; as an 

alternative a 0-30 ppmvw (as carbon) measurement range may 

be used.

(iv) Calibration gases will be propane in air and be 

certified through EPA Protocol 1 – “EPA Traceability 

Protocol for Assay and Certification of Gaseous Calibration 

Standards,” September 1997, as amended August 25, 1999, 

EPA–600/R–97/121 (or more recent if updated since 1999).

(v) THC measurements shall be reported in terms of 

ppmvw as propane.

(vi) THC results shall be corrected to 3 percent CO2, as 

measured by Method 3C, 40 CFR part 60, Appendix A.

(vii) Subtraction of methane/ethane from the THC data 
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is not allowed in determining results.

(7) Performance test criteria:

(i) The control device model tested must meet the 

criteria in paragraphs (g)(7)(i)(A) through (C) of this 

section:

(A) Method 22, 40 CFR part 60, Appendix A, results 

under paragraph (g)(5)(v) of this section with no 

indication of visible emissions, and

(B) Average Method 25A, 40 CFR part 60, Appendix A, 

results under paragraph (g)(6) of this section equal to or 

less than 10.0 ppmvw THC as propane corrected to 3.0 

percent CO2, and 

(C) Average CO emissions determined under paragraph 

(g)(5)(iv) of this section equal to or less than 10 parts 

ppmvd, corrected to 3.0 percent CO2.

(ii) The manufacturer shall determine a maximum inlet 

gas flow rate which shall not be exceeded for each control 

device model to achieve the criteria in paragraph (g)(7)(i) 

of this section.

(iii) A control device meeting the criteria in 

paragraph (g)(7)(i)(A) through (C) of this section will 

have demonstrated a destruction efficiency of 98.0 percent 
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for HAP regulated under this subpart.

(8) The owner or operator of a combustion control 

device model tested under this section shall submit the 

information listed in paragraphs (g)(8)(i) through (iii) in 

the test report required under §63.775(d)(1)(iii).

(i) Full schematic of the control device and 

dimensions of the device components.

(ii) Design net heating value (minimum and maximum) of 

the device.

(iii) Test fuel gas flow range (in both mass and 

volume). Include the minimum and maximum allowable inlet 

gas flow rate.

(iv) Air/stream injection/assist ranges, if used.

(v) The test parameter ranges listed in paragraphs 

(g)(8)(vi)(A) through (O) of this section, as applicable 

for the tested model. 

(A) Fuel gas delivery pressure and temperature.

(B) Fuel gas moisture range.

(C) Purge gas usage range.

(D) Condensate (liquid fuel) separation range.

(E) Combustion zone temperature range. This is 

required for all devices that measure this parameter.
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(F) Excess combustion air range.

(G) Flame arrestor(s).

(H) Burner manifold pressure.

(I) Pilot flame sensor.

(J) Pilot flame design fuel and fuel usage.

(K) Tip velocity range.

(L) Momentum flux ratio.

(M) Exit temperature range.

(N) Exit flow rate.

(O) Wind velocity and direction.

(vi) The test report shall include all calibration 

quality assurance/quality control data, calibration gas 

values, gas cylinder certification, and strip charts 

annotated with test times and calibration values. 

(h) Compliance demonstration for combustion control 

devices - manufacturers’ performance test. This paragraph 

applies to the demonstration of compliance for a combustion 

control device tested under the provisions in paragraph (g) 

of this section. Owners or operators shall demonstrate that 

a control device achieves the performance requirements of 

§63.1281(d)(1), (e)(3)(ii) or (f)(1), by installing a 

device tested under paragraph (g) of this section and 
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complying with the following criteria: 

(1) The inlet gas flow rate shall meet the range 

specified by the manufacturer. Flow rate shall be measured 

as specified in §63.1283(d)(3)(i)(H)(1).

(2) A pilot flame shall be present at all times of 

operation. The pilot flame shall be monitored in accordance 

with §63.1283 (d)(3)(i)(H)(2).

(3) Devices shall be operated with no visible 

emissions, except for periods not to exceed a total of 5 

minutes during any 2 consecutive hours. A visible emissions 

test using Method 22, 40 CFR part 60, Appendix A, shall be 

performed monthly. The observation period shall be 2 hours 

and shall be used according to Method 22. 

(4) Compliance with the operating parameter limit is 

achieved when the following criteria are met:

(i) The inlet gas flow rate monitored under paragraph 

(h)(1) of this section is equal to or below the maximum 

established by the manufacturer; and

(ii) The pilot flame is present at all times; and

(iii) During the visible emissions test performed 

under paragraph (h)(3) of this section the duration of 

visible emissions does not exceed a total of 5 minutes 
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during the observation period. Devices failing the visible 

emissions test shall follow the requirements in paragraphs 

(h)(4)(iii)(A) and (B) of this section.

(A) Following the first failure, the fuel nozzle(s) 

and burner tubes shall be replaced. 

(B) If, following replacement of the fuel nozzle(s) 

and burner tubes as specified in paragraph (h)(4)(iii)(A), 

the visible emissions test is not passed in the next 

scheduled test, either a performance test shall be 

performed under paragraph (d) of this section, or the 

device shall be replaced with another control device whose 

model was tested, and meets, the requirements in paragraph 

(g) of this section.

30. Section 63.1283 is amended by:

a. Revising paragraph (b);

b. Revising paragraph (d)(1) introductory text;

c. Revising paragraph (d)(1)(ii) and adding paragraphs 

(d)(1)(iii) and (iv);

d. Revising paragraph (d)(2)(i) and (d)(2)(ii);

e. Revising paragraphs (d)(3)(i)(A) and (B);

f. Revising paragraphs (d)(3)(i)(D) and (E);

g. Revising paragraphs (d)(3)(i)(F)(1) and (2);
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h. Revising paragraph (d)(3)(i)(G);

i. Adding paragraph (d)(3)(i)(H);

j. Revising paragraph (d)(4);

k. Revising paragraph (d)(5)(i) introductory text;

l. Revising paragraphs (d)(5)(i)(A) and (B);

m. Adding paragraph (d)(5)(i)(C);

n. Revising paragraphs (d)(5)(ii)(A) through (C);

o. Revising paragraph (d)(6) introductory text;

p. Revising paragraphs (d)(6)(ii);

q. Revising paragraph (d)(7)(v);

r. Revising paragraph (d)(8)(i)(A); and

s. Revising paragraph (d)(8)(ii) to read as follows:

§63.1283 Inspection and monitoring requirements.

* * * * *

(b) The owner or operator of a control device whose 

model was tested under 63.1282(g) shall develop an 

inspection and maintenance plan for each control device. At 

a minimum, the plan shall contain the control device 

manufacturer’s recommendations for ensuring proper 

operation of the device. Semi-annual inspections shall be 

conducted for each control device with maintenance and 
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replacement of control device components made in accordance 

with the plan.

(d) Control device monitoring requirements. (1) For 

each control device except as provided for in paragraph 

(d)(2) of this section, the owner or operator shall install 

and operate a continuous parameter monitoring system in 

accordance with the requirements of paragraphs (d)(3) 

through (9) of this section. Owners or operators that 

install and operate a flare in accordance with 

§63.1281(d)(1)(iii) or (f)(1)(iii) are exempt from the 

requirements of paragraphs (d)(4) and (5) of this section. 

The continuous monitoring system shall be designed and 

operated so that a determination can be made on whether the 

control device is achieving the applicable performance 

requirements of §63.1281(d), (e)(3), or (f)(1). Each 

continuous parameter monitoring system shall meet the 

following specifications and requirements:

* * * * *

(ii) A site-specific monitoring plan must be prepared 

that addresses the monitoring system design, data 

collection, and the quality assurance and quality control 

elements outlined in paragraph (d) of this section and in 
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§63.8(d). Each CPMS must be installed, calibrated, 

operated, and maintained in accordance with the procedures 

in your approved site-specific monitoring plan. Using the 

process described in §63.8(f)(4), you may request approval 

of monitoring system quality assurance and quality control 

procedures alternative to those specified in paragraphs 

(d)(1)(ii)(A) through (E) of this section in your sitespecific monitoring plan.

(A) The performance criteria and design 

specifications for the monitoring system equipment, 

including the sample interface, detector signal analyzer, 

and data acquisition and calculations;

(B) Sampling interface (e.g., thermocouple) location 

such that the monitoring system will provide representative 

measurements; 

(C) Equipment performance checks, system accuracy 

audits, or other audit procedures;

(D) Ongoing operation and maintenance procedures in 

accordance with provisions in §63.8(c)(1) and (c)(3); and

(E) Ongoing reporting and recordkeeping procedures in 

accordance with provisions in §63.10(c), (e)(1), and 

(e)(2)(i).
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(iii) The owner or operator must conduct the CPMS 

equipment performance checks, system accuracy audits, or 

other audit procedures specified in the site-specific 

monitoring plan at least once every 12 months.

(iv) The owner or operator must conduct a performance 

evaluation of each CPMS in accordance with the sitespecific monitoring plan.

(2) * * *

(i) Except for control devices for small glycol 

dehydration units, a boiler or process heater in which all 

vent streams are introduced with the primary fuel or are 

used as the primary fuel;

(ii) Except for control devices for small glycol 

dehydration units, a boiler or process heater with a design 

heat input capacity equal to or greater than 44 megawatts.

(3) * * *

(i) * * *

(A) For a thermal vapor incinerator that demonstrates 

during the performance test conducted under §63.1282(d) 

that combustion zone temperature is an accurate indicator 

of performance, a temperature monitoring device equipped 

with a continuous recorder. The monitoring device shall 
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have a minimum accuracy of ±1 percent of the temperature 

being monitored in degrees C, or ±2.5 degrees C, whichever 

value is greater. The temperature sensor shall be installed 

at a location representative of the combustion zone

temperature.

(B) For a catalytic vapor incinerator, a temperature 

monitoring device equipped with a continuous recorder. The 

device shall be capable of monitoring temperatures at two 

locations and have a minimum accuracy of ±1 percent of the 

temperatures being monitored in degrees C, or ±2.5 degrees 

C, whichever value is greater. One temperature sensor shall 

be installed in the vent stream at the nearest feasible 

point to the catalyst bed inlet and a second temperature 

sensor shall be installed in the vent stream at the nearest 

feasible point to the catalyst bed outlet.

* * * * *

(D) For a boiler or process heater, a temperature 

monitoring device equipped with a continuous recorder. The 

temperature monitoring device shall have a minimum accuracy 

of ±1 percent of the temperature being monitored in degrees 

C, or ±2.5 degrees C, whichever value is greater. The 
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temperature sensor shall be installed at a location 

representative of the combustion zone temperature.

(E) For a condenser, a temperature monitoring device 

equipped with a continuous recorder. The temperature 

monitoring device shall have a minimum accuracy of ±1 

percent of the temperature being monitored in degrees C, or 

±2.8 degrees C, whichever value is greater. The temperature 

sensor shall be installed at a location in the exhaust vent 

stream from the condenser.

(F) * * *

(1) A continuous parameter monitoring system to 

measure and record the average total regeneration stream 

mass flow or volumetric flow during each carbon bed 

regeneration cycle. The flow sensor must have a measurement 

sensitivity of 5 percent of the flow rate or 10 cubic feet 

per minute, whichever is greater. The mechanical 

connections for leakage must be checked at least every 

month, and a visual inspection must be performed at least 

every 3 months of all components of the flow CPMS for 

physical and operational integrity and all electrical 

connections for oxidation and galvanic corrosion if your 

flow CPMS is not equipped with a redundant flow sensor; and
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(2) A continuous parameter monitoring system to 

measure and record the average carbon bed temperature for 

the duration of the carbon bed steaming cycle and to 

measure the actual carbon bed temperature after 

regeneration and within 15 minutes of completing the 

cooling cycle. The temperature monitoring device shall have 

a minimum accuracy of ±1 percent of the temperature being 

monitored in degrees C, or ±2.5 degrees C, whichever value 

is greater.

(G) For a nonregenerative-type carbon adsorption 

system, the owner or operator shall monitor the design 

carbon replacement interval established using a performance 

test performed in accordance with §63.1282(d)(3) and shall 

be based on the total carbon working capacity of the 

control device and source operating schedule.

(H) For a control device whose model is tested under 

§63.1282(g):

(1) A continuous monitoring system that measures gas 

flow rate at the inlet to the control device. The 

monitoring instrument shall have an accuracy of plus or 

minus 2 percent or better.
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(2) A heat sensing monitoring device equipped with a 

continuous recorder that indicates the continuous ignition 

of the pilot flame.

* * * * *

(4) Using the data recorded by the monitoring system, 

except for inlet gas flowrate, the owner or operator must 

calculate the daily average value for each monitored 

operating parameter for each operating day. If the 

emissions unit operation is continuous, the operating day 

is a 24-hour period. If the emissions unit operation is not 

continuous, the operating day is the total number of hours 

of control device operation per 24-hour period. Valid data 

points must be available for 75 percent of the operating 

hours in an operating day to compute the daily average.

(5) * * *

(i) The owner or operator shall establish a minimum 

operating parameter value or a maximum operating parameter 

value, as appropriate for the control device, to define the 

conditions at which the control device must be operated to 

continuously achieve the applicable performance 

requirements of §63.1281(d)(1), (e)(3)(ii), or (f)(1). Each 
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minimum or maximum operating parameter value shall be 

established as follows:

(A) If the owner or operator conducts performance 

tests in accordance with the requirements of §63.1282(d)(3) 

to demonstrate that the control device achieves the 

applicable performance requirements specified in 

§63.1281(d)(1), (e)(3)(ii), or (f)(1), then the minimum 

operating parameter value or the maximum operating 

parameter value shall be established based on values 

measured during the performance test and supplemented, as 

necessary, by a condenser design analysis or control device 

manufacturer's recommendations or a combination of both.

(B) If the owner or operator uses a condenser design 

analysis in accordance with the requirements of 

§63.1282(d)(4) to demonstrate that the control device 

achieves the applicable performance requirements specified 

in §63.1281(d)(1), (e)(3)(ii), or (f)(1), then the minimum 

operating parameter value or the maximum operating 

parameter value shall be established based on the condenser 

design analysis and may be supplemented by the condenser 

manufacturer's recommendations.
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(C) If the owner or operator operates a control device 

where the performance test requirement was met under 

§63.1282(g) to demonstrate that the control device achieves 

the applicable performance requirements specified in 

§63.1281(d)(1), (e)(3)(ii) or (f)(1), then the maximum 

inlet gas flow rate shall be established based on the 

performance test and supplemented, as necessary, by the 

manufacturer recommendations.

(ii) * * *

(A) If the owner or operator conducts a performance 

test in accordance with the requirements of §63.1282(d)(3) 

to demonstrate that the condenser achieves the applicable 

performance requirements in §63.1281(d)(1), (e)(3)(ii), or 

(f)(1), then the condenser performance curve shall be based 

on values measured during the performance test and 

supplemented as necessary by control device design 

analysis, or control device manufacturer's recommendations, 

or a combination or both.

(B) If the owner or operator uses a control device 

design analysis in accordance with the requirements of 

§63.1282(d)(4)(i) to demonstrate that the condenser 

achieves the applicable performance requirements specified 
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in §63.1281(d)(1), (e)(3)(ii), or (f)(1), then the 

condenser performance curve shall be based on the condenser 

design analysis and may be supplemented by the control 

device manufacturer's recommendations.

(C) As an alternative to paragraph (d)(5)(ii)(B) of 

this section, the owner or operator may elect to use the 

procedures documented in the GRI report entitled, 

“Atmospheric Rich/Lean Method for Determining Glycol 

Dehydrator Emissions” (GRI–95/0368.1) as inputs for the 

model GRI-GLYCalcTM, Version 3.0 or higher, to generate a 

condenser performance curve.

(6) An excursion for a given control device is 

determined to have occurred when the monitoring data or 

lack of monitoring data result in any one of the criteria 

specified in paragraphs (d)(6)(i) through (d)(6)(v) of this 

section being met. When multiple operating parameters are 

monitored for the same control device and during the same 

operating day, and more than one of these operating 

parameters meets an excursion criterion specified in 

paragraphs (d)(6)(i) through (d)(6)(iv) of this section, 

then a single excursion is determined to have occurred for 

the control device for that operating day.
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* * * * *

(ii) For sources meeting §63.1281(d)(1)(ii), an 

excursion occurs when average condenser efficiency 

calculated according to the requirements specified in 

§63.1282(f)(2)(iii) is less than 95.0 percent, as specified 

in §63.1282(f)(3). For sources meeting §63.1281(f)(1), an 

excursion occurs when the 30-day average condenser 

efficiency calculated according to the requirements of 

§63.1282(f)(2)(iii) is less than the identified 30-day 

required percent reduction.

* * * * *

(v) For control device whose model is tested under

§63.1282(g) an excursion occurs when:

(A) The inlet gas flow rate exceeds the maximum 

established during the test conducted under §63.1282(g).

(B) Failure of the monthly visible emissions test 

conducted under §63.1282(h)(3) occurs.

(8) * * *

(i) * * *

(A) During a malfunction when the affected facility is 

operated during such period in accordance with §63.6(e)(1); 

or
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* * * * *

(ii) For each control device, or combinations of 

control devices, installed on the same emissions unit, one 

excused excursion is allowed per semiannual period for any 

reason. The initial semiannual period is the 6-month 

reporting period addressed by the first Periodic Report 

submitted by the owner or operator in accordance with 

§63.1285(e) of this subpart.

* * * * *

31. Section 63.1284 is amended by:

a. Revising paragraph (b)(3) introductory text;

b. Deleting and reserving paragraph (b)(3)(ii);

c. Revising paragraph (b)(4)(ii) introductory text;

d. Adding paragraph (b)(4)(ii)(A) through (C);

e. Adding paragraph (b)(7)(ix); and

f. Adding paragraph (f), (g) and (h) to read as 

follows:

§63.1284 Recordkeeping requirements.

* * * * *

(b) * * *

* * * * *
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(3) Records specified in §63.10(c) for each monitoring 

system operated by the owner or operator in accordance with 

the requirements of §63.1283(d). Notwithstanding the 

previous sentence, monitoring data recorded during periods 

identified in paragraphs (b)(3)(i) through (iv) of this 

section shall not be included in any average or percent 

leak rate computed under this subpart. Records shall be 

kept of the times and durations of all such periods and any 

other periods during process or control device operation 

when monitors are not operating or failed to collect 

required data.

* * * * *

(ii) [Reserved]

* * * * *

(4) * * *

* * * * *

(ii) Records of the daily average value of each 

continuously monitored parameter for each operating day 

determined according to the procedures specified in 

§63.1283(d)(4) of this subpart, except as specified in 

paragraphs (b)(4)(ii)(A) through (C) of this section.

(A) For flares, the records required in paragraph (e) 
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of this section.

(B)_For condensers installed to comply with §63.1275, 

records of the annual 30-day rolling average condenser 

efficiency determined under §63.1282(f) shall be kept in 

addition to the daily averages.

(C) For a control device whose model is tested under 

§63.1282(g), the records required in paragraph (g) of this 

section.

* * * * *

(7) * * *

(ix) Records identifying the carbon replacement 

schedule under §63.1281(d)(5) and records of each carbon 

replacement.

* * * * *

(f) The owner or operator of an affected source 

subject to this subpart shall maintain records of the 

occurrence and duration of each malfunction of operation 

(i.e., process equipment) or the air pollution control 

equipment and monitoring equipment. The owner or operator 

shall maintain records of actions taken during periods of 

malfunction to minimize emissions in accordance with 

§63.1274(a), including corrective actions to restore 
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malfunctioning process and air pollution control and 

monitoring equipment to its normal or usual manner of 

operation.

(g) Record the following when using a control device 

whose model is tested under §63.1282(g) to comply with 

§63.1281(d), (e)(3)(ii) and (f)(1):

(1) All visible emission readings and flowrate 

measurements made during the compliance determination 

required by §63.1282(h); and

(2) All hourly records and other recorded periods when 

the pilot flame is absent.

(h) The date the semi-annual maintenance inspection 

required under §63.1283(b) is performed. Include a list of 

any modifications or repairs made to the control device 

during the inspection and other maintenance performed such 

as cleaning of the fuel nozzles.

32. Section 63.1285 is amended by:

a. Revising paragraph (b)(1) introductory text;

b. Adding paragraphs (b)(1)(i) and (ii);

c. Revising paragraph (b)(6);

d. Deleting and reserving paragraph (b)(7);

e. Revising paragraph (d)(1) introductory text;
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f. Revising paragraphs (d)(1)(i);

g. Revising paragraph (d)(1)(ii) introductory text;

h. Revising paragraph (d)(2) introductory text;

i. Revising paragraph (d)(2)(ii);

j. Revising paragraph (d)(4)(ii);

k. Adding paragraph (d)(4)(iv);

l. Revising paragraph (d)(10);

m. Adding paragraphs (d)(11) and (d)(12);

n. Revising paragraph (e)(2) introductory text;

o. Revising paragraphs (e)(2)(ii)(B);

p. Adding paragraphs (e)(2)(ii)(D) and (E);

q. Adding paragraphs (e)(2)(x),(xi) and (xii); and

r. Adding paragraph (g) to read as follows:

§63.1285 Reporting requirements.

* * * * *

(b) * * *

(1) The initial notifications required for existing 

affected sources under §63.9(b)(2) shall be submitted as 

provided in paragraphs (b)(1)(i) and (ii) of this section.

(i) Except as otherwise provided in paragraph (ii), 

the initial notification shall be submitted by 1 year after 

an affected source becomes subject to the provisions of 
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this subpart or by June 17, 2000, whichever is later. 

Affected sources that are major sources on or before June 

17, 2000 and plan to be area sources by June 17, 2002 shall 

include in this notification a brief, nonbinding 

description of a schedule for the action(s) that are 

planned to achieve area source status.

(ii) An affected source identified under 

§63.1270(d)(3) shall submit an initial notification 

required for existing affected sources under §63.9(b)(2) 

within 1 year after the affected source becomes subject to 

the provisions of this subpart or by one year after 

publication of the final rule in the Federal Register, 

whichever is later. An affected source identified under 

§63.1270(d)(3) that plans to be an area source by three 

years after publication of the final rule in the Federal 

Register, shall include in this notification a brief, 

nonbinding description of a schedule for the action(s) that 

are planned to achieve area source status.

* * * * *

(6) If there was a malfunction during the reporting 

period, the Periodic Report specified in paragraph (e) of 

this section shall include the number, duration, and a 
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brief description for each type of malfunction which 

occurred during the reporting period and which caused or 

may have caused any applicable emission limitation to be 

exceeded. The report must also include a description of 

actions taken by an owner or operator during a malfunction 

of an affected source to minimize emissions in accordance 

with §63.1274(h), including actions taken to correct a 

malfunction.

(7) [Reserved]

* * * * *

(d) * * *

(1) If a closed-vent system and a control device other 

than a flare are used to comply with §63.1274, the owner or 

operator shall submit the information in paragraph 

(d)(1)(iii) of this section and the information in either 

paragraph (d)(1)(i) or(ii) of this section.

(i) The condenser design analysis documentation 

specified in §63.1282(d)(4) of this subpart if the owner or 

operator elects to prepare a design analysis; or

(ii) If the owner or operator is required to conduct a 

performance test, the performance test results including 

the information specified in paragraphs (d)(1)(ii)(A) and 
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(B) of this section. Results of a performance test 

conducted prior to the compliance date of this subpart can 

be used provided that the test was conducted using the 

methods specified in §63.1282(d)(3), and that the test 

conditions are representative of current operating 

conditions. If the owner or operator operates a combustion 

control device model tested under §63.1282(g), an 

electronic copy of the performance test results shall be 

submitted via email to Oil_and_Gas_PT@EPA.GOV.

* * * * *

(2) If a closed-vent system and a flare are used to 

comply with §63.1274, the owner or operator shall submit 

performance test results including the information in 

paragraphs (d)(2)(i) and (ii) of this section. The owner 

or operator shall also submit the information in paragraph 

(d)(2)(iii) of this section.

* * * * *

(ii) A statement of whether a flame was present at the 

pilot light over the full period of the compliance 

determination.

* * * * *

(4) * * *
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* * * * *

(ii) An explanation of the rationale for why the owner 

or operator selected each of the operating parameter values 

established in §63.1283(d)(5) of this subpart. This 

explanation shall include any data and calculations used to 

develop the value, and a description of why the chosen 

value indicates that the control device is operating in 

accordance with the applicable requirements of 

§63.1281(d)(1), (e)(3)(ii), or (f)(1).

* * * * *

(iv) For each carbon adsorber, the predetermined 

carbon replacement schedule as required in 

§63.1281(d)(5)(i).

* * * * *

(10) The owner or operator shall submit the analysis 

prepared under §63.1281(e)(2) to demonstrate that the 

conditions by which the facility will be operated to 

achieve the HAP emission reduction of 95.0 percent, or the 

BTEX limit in §63.1275(b)(1)(iii) through process 

modifications or a combination of process modifications and 

one or more control devices.

(11) If the owner or operator installs a combustion 
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control device model tested under the procedures in 

§63.1282(g), the data listed under §63.1282(g)(8).

(12) For each combustion control device model tested 

under §63.1282(g), the information listed in paragraphs 

(d)(12)(i) through (vi) of this section.

(i) Name, address and telephone number of the control 

device manufacturer.

(ii) Control device model number.

(iii) Control device serial number.

(iv) Date of control device certification test.

(v) Manufacturer’s HAP destruction efficiency rating.

(vi) Control device operating parameters, maximum 

allowable inlet gas flowrate.

* * * * *

(e) * * *

* * * * *

(2) The owner or operator shall include the 

information specified in paragraphs (e)(2)(i) through (xii) 

of this section, as applicable.

* * * * *

(ii) * * *

* * * * *
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(B) For each excursion caused when the 30-day average 

condenser control efficiency is less than the value, as 

specified in §63.1283(d)(6)(ii), the report must include 

the 30-day average values of the condenser control 

efficiency, and the date and duration of the period that 

the excursion occurred.

* * * * *

(D) For each excursion caused when the maximum inlet 

gas flow rate identified under §63.1282(g) is exceeded, the 

report must include the values of the inlet gas identified 

and the date and duration of the period that the excursion 

occurred.

(E) For each excursion caused when visible emissions 

determined under §63.1282(h) exceed the maximum allowable 

duration, the report must include the date and duration of 

the period that the excursion occurred.

* * * * *

(x) The results of any periodic test as required in 

§63.1282(d)(3) conducted during the reporting period.

(xi) For each carbon adsorber used to meet the control 

device requirements of §63.1281(d)(1), records of each 
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carbon replacement that occurred during the reporting 

period.

(xii) For combustion control device inspections 

conducted in accordance with §63.1283(b) the records 

specified in §63.1284(h).

* * * * *

(g) Electronic Reporting. (1) As of January 1, 2012,

and within 60 days after the date of completing each 

performance test, as defined in §63.2 and as required in 

this subpart, you must submit performance test data, except 

opacity data, electronically to the EPA’s Central Data 

Exchange (CDX) by using the Electronic Reporting Tool (ERT) 

(see http://www.epa.gov/ttn/chief/ert/ert tool.html/). Only 

data collected using test methods compatible with ERT are 

subject to this requirement to be submitted electronically 

into the EPA’s WebFIRE database. 

(2) All reports required by this subpart not subject 

to the requirements in paragraphs (g)(1) of this section 

must be sent to the Administrator at the appropriate 

address listed in §63.13. If acceptable to both the 

Administrator and the owner or operator of a source, these 

reports may be submitted on electronic media. The 
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Administrator retains the right to require submittal of 

reports subject to paragraph (g)(1) of this section in 

paper format.

* * * * *

33. Section 63.1287 is amended by revising paragraph 

(a) to read as follows:

(a) If, in the judgment of the Administrator, an 

alternative means of emission limitation will achieve a 

reduction in HAP emissions at least equivalent to the 

reduction in HAP emissions from that source achieved under 

the applicable requirements in §§63.1274 through 63.1281, 

the Administrator will publish a notice in the Federal 

Register permitting the use of the alternative means for 

purposes of compliance with that requirement. The notice 

may condition the permission on requirements related to the 

operation and maintenance of the alternative means.

34. Appendix to Subpart HHH of Part 63 – Table is 

amended by revising Table 2 to read as follows:

Appendix to Subpart HHH of Part 63—Tables

* * * * *

Table 2 to Subpart HHH of Part 63—Applicability of 40 CFR 

Part 63 General Provisions to Subpart HHH

General provisions 

reference

Applicable 

to

Explanation
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subpart HHH

§63.1(a)(1) ..... Yes.

§63.1(a)(2) ..... Yes.

§63.1(a)(3) ..... Yes.

§63.1(a)(4) ..... Yes.

§63.1(a)(5) ..... No ............................ Section reserved.

§63.1(a)(6) .....

through (a)(8)

Yes.

§63.1(a)(9) ..... No ............................ Section reserved.

§63.1(a)(10) .... Yes.

§63.1(a)(11) .... Yes.

§63.1(a)(12) ....

through (a)(14)

Yes.

§63.1(b)(1) ..... No ............................ Subpart HHH specifies 

applicability.

§63.1(b)(2) ..... Yes.

§63.1(b)(3) ..... No.

§63.1(c)(1) ..... No ............................ Subpart HHH specifies 

applicability.

§63.1(c)(2) ..... No.

§63.1(c)(3) ..... No ............................ Section reserved.

§63.1(c)(4) ..... Yes.

§63.1(c)(5) ..... Yes.

§63.1(d) ........ No ............................ Section reserved.

§63.1(e) ........ Yes.

§63.2 ........... Yes ........................... Except definition of major 

source is unique for this source 

category and there are 

additional definitions in 

subpart HHH.

§63.3(a) through 

(c)

Yes.

§63.4(a)(1) .....

through (a)(3)

Yes.

§63.4(a)(4) ..... No ............................ Section reserved.

§63.4(a)(5) ..... Yes.

§63.4(b) ........ Yes.

§63.4(c) ........ Yes.

§63.5(a)(1) ..... Yes.

§63.5(a)(2) ..... No ............................ Preconstruction review required 

only for major sources that 

commence construction after 

promulgation of the standard.

§63.5(b)(1) ..... Yes.
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§63.5(b)(2) ..... No ............................ Section reserved.

§63.5(b)(3) ..... Yes.

§63.5(b)(4) ..... Yes.

§63.5(b)(5) ..... Yes.

§63.5(b)(6) ..... Yes.

§63.5(c) ........ No ............................ Section reserved.

§63.5(d)(1) ..... Yes.

§63.5(d)(2) ..... Yes.

§63.5(d)(3) ..... Yes.

§63.5(d)(4) ..... Yes.

§63.5(e) ........ Yes.

§63.5(f)(1) ..... Yes.

§63.5(f)(2) ..... Yes.

§63.6(a) ........ Yes.

§63.6(b)(1) ..... Yes.

§63.6(b)(2) ..... Yes.

§63.6(b)(3) ..... Yes.

§63.6(b)(4) ..... Yes.

§63.6(b)(5) ..... Yes.

§63.6(b)(6) ..... No ............................ Section reserved.

§63.6(b)(7) ..... Yes.

§63.6(c)(1) ..... Yes.

§63.6(c)(2) ..... Yes.

§63.6(c)(3) and 

(c)(4)

No ............................ Section reserved.

§63.6(c)(5) ..... Yes.

§63.6(d) ........ No ............................ Section reserved.

§63.6(e) ........ Yes.

§63.6(e) ........ Yes ........................... Except as otherwise specified.

§63.6(e)(1)(i) .. No ............................ See §63.1274(h) for general duty 

requirement.

§63.6(e)(1)(ii) No.

§63.6(e)(1)(iii) Yes.

§63.6(e)(2) ..... Yes.

§63.6(e)(3) ..... No.

§63.6(f)(1) ..... No.

§63.6(f)(2) ..... Yes.

§63.6(f)(3) ..... Yes.

§63.6(g) ........ Yes.

§63.6(h) ........ No ............................ Subpart HHH does not contain 

opacity or visible emission 

standards.

§63.6(i)(1) .....

through (i)(14)

Yes.
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§63.6(i)(15) .... No ............................ Section reserved.

§63.6(i)(16) .... Yes.

§63.6(j) ........ Yes.

§63.7(a)(1) ..... Yes.

§63.7(a)(2) ..... Yes ........................... But the performance test results 

must be submitted within 180 

days after the compliance date.

§63.7(a)(3) ..... Yes.

§63.7(b) ........ Yes.

§63.7(c) ........ Yes.

§63.7(d) ........ Yes.

§63.7(e)(1) ..... No.

§63.7(e)(2) ..... Yes.

§63.7(e)(3) ..... Yes.

§63.7(e)(4) ..... Yes.

§63.7(f) ........ Yes.

§63.7(g) ........ Yes.

§63.7(h) ........ Yes.

§63.8(a)(1) ..... Yes.

§63.8(a)(2) ..... Yes.

§63.8(a)(3) ..... No ............................ Section reserved.

§63.8(a)(4) ..... Yes.

§63.8(b)(1) ..... Yes.

§63.8(b)(2) ..... Yes.

§63.8(b)(3) ..... Yes.

§63.8(c)(1) ..... Yes.

63.8(c)(1)(i).

§63.8(c)(1)(ii).

§63.8(c)(1)(iii)

No

Yes

Pending

§63.8(c)(2) ..... Yes.

§63.8(c)(3) ..... Yes.

§63.8(c)(4) ..... No.

§63.8(c)(5) .....

through (c)(8)

Yes.

§63.8(d) ........ Yes.

§63.8(d)(3) ..... Yes ........................... Except for last sentence, which 

refers to an SSM plan. SSM plans 

are not required.

§63.8(e) ........ Yes ............................ Subpart HHH does not 

specifically require continuous 

emissions monitor performance 

evaluations, however, the 

Administrator can request that 

one be conducted.
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§63.8(f)(1) .....

through (f)(5)

Yes ............................

§63.8(f)(6) ..... No ............................ Subpart HHH does not require 

continuous emissions monitoring.

§63.8(g) ........ No ............................ Subpart HHH specifies continuous 

monitoring system data reduction 

requirements.

§63.9(a) ........ Yes.

§63.9(b)(1) ..... Yes.

§63.9(b)(2) ..... Yes ........................... Existing sources are given 1 

year (rather than 120 days) to 

submit this notification.

§63.9(b)(3) ..... Yes.

§63.9(b)(4) ..... Yes.

§63.9(b)(5) ..... Yes.

§63.9(c) ........ Yes.

§63.9(d) ........ Yes.

§63.9(e) ........ Yes.

§63.9(f) ........ No.

§63.9(g) ........ Yes.

§63.9(h)(1) .....

through (h)(3)

Yes.

§63.9(h)(4) ..... No ............................ Section reserved.

§63.9(h)(5) and .

(h)(6)

Yes.

§63.9(i) ........ Yes.

§63.9(j) ........ Yes.

§63.10(a) ....... Yes.

§63.10(b)(1) .... Yes ........................... Section 63.1284(b)(1) requires 

sources to maintain the most 

recent 12 months of data on-site 

and allows offsite storage for 

the remaining 4 years of data.

§63.10(b)(2) .... Yes.

§63.10(b)(2)(i) . No ............................

§63.10(b)(2)(ii) No ............................ See §63.1284(f) for 

recordkeeping of occurrence, 

duration, and actions taken 

during malfunction

§63.10(b)(2)(iii) Yes.

§63.10(b)(2)(iv)

through (b)(2)(v)

No.

§63.10(b)(2)(vi)

through 

Yes.
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(b)(2)(xiv)

§63.10(b)(3) .... No.

§63.10(c)(1) .... Yes.

§63.10(c)(2) ....

through (c)(4)

No ............................ Sections reserved.

§63.10(c)(5) ....

through (c)(8)

Yes.

§63.10(c)(9) .... No ............................ Section reserved.

§63.10(c)(10) and 

(c)(11)

No ............................ See §63.1284(f)for recordkeeping 

of malfunctions

§63.10(c)(12) ...

through (c)(14)

Yes.

§63.10(c)(15) ... No.

§63.10(d)(1) .... Yes.

§63.10(d)(2) .... Yes.

§63.10(d)(3) .... Yes.

§63.10(d)(4) .... Yes.

§63.10(d)(5) .... No ............................ See §63.1285(b)(6) for reporting 

of malfunctions.

§63.10(e)(1) .... Yes.

§63.10(e)(2) .... Yes.

§63.10(e)(3)(i) . Yes ............................ Subpart HHH requires major 

sources to submit Periodic 

Reports semi-annually.

§63.10(e)(3)(i)(A) Yes.

§63.10(e)(3)(i)(B) Yes.

§63.10(e)(3)(i)(C) No ............................ Subpart HHH does not require 

quarterly reporting for excess 

emissions.

§63.10(e)(3)(ii)

through 

(e)(3)(viii)

Yes.

§63.10(f) ....... Yes.

§63.11(a) and (b) Yes.

§63.11(c), (d), .

and (e)

Yes.

§63.12(a) through

(c)

Yes.

§63.13(a) through

(c)

Yes.

§63.14(a) and (b) Yes.

§63.15(a) and (b) Yes.