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***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release 

During Review***

E.O. 12866 NSPS and NESHAP for Oil and Gas 2060-AP76 Final Rule 

20120223

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

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

RIN 2060-AP76

Oil and Natural Gas Sector: New Source Performance Standards and 

National Emission Standards for Hazardous Air Pollutants Reviews

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

SUMMARY: This action finalizes the review conducted under 

section 111(b) of the Clean Air Act of new source performance 

standards for the listed oil and natural gas source category. In 

this action the EPA revised the new source performance standards

for volatile organic compounds from leaking components at 

onshore natural gas processing plants (40 CFR part 60, subpart 

KKK) and new source performance standards for sulfur dioxide 

emissions from natural gas processing plants (40 CFR part 60, 

subpart LLL). The EPA also established standards (40 CFR part 

60, subpart OOOO) for certain oil and gas operations not covered 
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by the existing standards. In addition to the operations covered 

by subparts KKK and LLL, subpart OOOO will regulate volatile 

organic compound emissions from gas wells, centrifugal 

compressors, reciprocating compressors, pneumatic controllers, 

and storage vessels. This action also finalizes the residual 

risk and technology review conducted under section 112 of the 

Clean Air Act for the Oil and Natural Gas Production Facilities 

source category (40 CFR part 63, subpart HH) and the Natural Gas 

Transmission and Storage Facilities source category (40 CFR part 

63, subpart HHH). This action includes revisions to the existing

emission limit for glycol dehydration unit process vents and 

leak detection and repair requirements. In addition, pursuant to 

section 112(d)(2) and (3), the EPA has established in this 

action emission limits reflecting maximum achievable control 

technology for certain currently uncontrolled emission sources 

in these source categories. This action also includes

modification and addition of testing and monitoring and related 

notification, recordkeeping and reporting requirements, as well 

as other minor technical revisions to the national emission 

standards for hazardous air pollutants. This action finalizes 

revisions to the regulatory provisions related to emissions 

during periods of startup, shutdown and malfunction.

DATES: This final rule is effective on [INSERT DATE 60 DAYS

AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER]. The
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incorporation by reference of certain publications listed in

this rule is approved by the Director of the Federal Register as

of [INSERT DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE

FEDERAL REGISTER].

ADDRESSES: The EPA has established a docket for this action 

under Docket ID. No. EPA-HQ-OAR-2010-0505. All documents in the

docket are listed on the http://www.regulations.gov website. 

Although listed in the index, some information is not publicly 

available, e.g., confidential business information or other 

information whose disclosure is restricted by statute. Certain 

other material, such as copyrighted material, is not placed on

the Internet and will be publicly available only in hard copy 

form. Publicly available docket materials are available either 

electronically through http://www.regulations.gov or in hard 

copy at the EPA’s Docket Center, Public Reading Room, EPA West 

Building, Room Number 3334, 1301 Constitution Avenue, NW, 

Washington, D.C. 20004. This Docket Facility is open from 8:30 

a.m. to 4:30 p.m. Eastern Standard Time, 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) 566-1741.

FOR FURTHER INFORMATION CONTACT: For further information about 

this final action, contact Mr. Bruce Moore, Sector Policies and 

Programs Division, Office of Air Quality and Standards (E143-
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05), 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. For additional contact information, see the 

following SUPPLEMENTARY INFORMATION section.

SUPPLEMENTARY INFORMATION: For specific information regarding 

risk assessment and exposure modeling methodology, contact Mr. 

Mark Morris, Health and Environmental Impacts Division, Office 

of Air Quality Planning and Standards (C504-06), U.S. 

Environmental Protection Agency, Research Triangle Park, NC 

27711; telephone number (919) 541-5416; fax number: (919) 541-

0840; and e-mail address: morris.mark@epa.gov. 

Organization of This Document. The information presented in 

this preamble is organized as follows:

I. Preamble Acronyms and Abbreviations

II. General Information

A. Executive Summary

B. Does this action apply to me?

C. What are the emission sources affected by this action?

D. Where can I get a copy of this document?

E. Judicial Review

III. Background Information on the NSPS and NESHAP

A. What are the statutory authorities for the NSPS and NESHAP?

B. What is the litigation history?
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C. What is the sector-based approach?

D. What are the health effects of pollutants emitted from the 

oil and natural gas sector?

IV. Summary of the Final NSPS Rule

A. What are the final rule revisions to the NSPS for the Crude 

Oil and Natural Gas Production, Transmission, and Distribution 

source category?

B. What are the effective and compliance dates for the final

NSPS?

V. Summary of the Significant Changes to the NSPS Since Proposal

A. Gas well affected facilities

B. Centrifugal and reciprocating compressor affected facilities

C. Pneumatic controller affected facilities

D. Storage vessel affected facilities

E. Equipment leaks affected facilities and sweetening unit 

affected facilities at onshore natural gas processing plants

F. Changes to notification, recordkeeping and reporting 

requirements

VI. Summary of the Final NESHAP Rules

A. What are the final rule amendments for the Oil and Natural 

Gas Production Facilities (subpart HH) source category?

B. What are the final rule amendments for the Natural Gas 

Transmission and Storage facilities (subpart HHH) source 

category?
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C. What are the effective and compliance dates of the standards?

D. How do the final NESHAPs provide for compliance assurance?

E. What are the requirements for submission of performance test 

data to the EPA?

VII. Summary of the Significant Changes to the NESHAP Since 

Proposal

A. What are the significant changes since proposal for the Oil 

and Natural Gas Production Facilities (subpart HH) source 

category?

B. What are the significant changes since proposal for the 

Natural Gas Transmission and Storage facilities (subpart HHH) 

source category?

VIII. Compliance Related Issues Common to the NSPS and NESHAP

A. How do the rules address startup, shutdown and malfunction?

B. How do the NSPS and NESHAP provide for compliance assurance?

C. What are the requirements for submission of performance test 

data to the EPA?

IX. Summary of Significant NSPS Comments and Responses 

A. Major comments concerning applicability 

B. Major comments concerning well completions

C. Major comments concerning pneumatic controllers

D. Major comments concerning compressors

E. Major comments concerning storage vessels

F. Major comments concerning equipment leaks
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G. Major comments concerning notification, recordkeeping and 

reporting requirements

X. Summary of Significant NESHAP Comments and Responses

A. Major comments concerning applicability

B. Major comments concerning the risk review

C. Major comments concerning the previously unregulated sources

D. Major comments concerning the technology review

E. Major comments concerning notification, recordkeeping and 

reporting requirements

XI. What are the cost, environmental and economic impacts of the 

final NSPS and NESHAP amendments?

A. What are the air impacts?

B. What are the energy impacts?

C. What are the cost impacts?

D. What are the economic impacts?

E. What are the benefits of this final rule?

XII. Statutory and Executive Order Reviews

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
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F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

G. Executive Order 13045: Protection of Children from

Environmental Health Risks 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

K. Congressional Review Act

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
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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

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
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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 NEI code 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 bioaccumulative 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
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PPMV Parts Per Million by Volume

PSIG Pounds Per Square Inch Gauge

PSIA Pounds Per Square Inch Absolute

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

SCM Standard Cubic Meters

SCMD Standard Cubic Meters Per Day

SCOT Shell Claus Offgas Treatment

SIP State Implementation Plan
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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. Executive Summary

1. Purpose of the Regulatory Action
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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 that, as modified, requires the EPA to 

sign by July 28, 2011, 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 April 3, 

2012.

This action finalizes the review conducted under section 

111(b) of the Clean Air Act of new source performance standards 

for the listed oil and natural gas source category. This action 

also finalizes the residual risk and technology review conducted 

under section 112 of the Clean Air Act for the Oil and Natural 

Gas Production Facilities source category (40 CFR part 63, 

subpart HH) and the Natural Gas Transmission and Storage 

Facilities source category (40 CFR part 63, subpart HHH). In 

addition, pursuant to section 112(d)(2) and (3), the EPA has 

established in this action emission limits reflecting maximum 

achievable control technology for certain currently uncontrolled 

emission sources in these source categories.
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2. Summary of the Major Provisions of the Regulatory Action

In this action the EPA revised the new source performance 

standards for volatile organic compounds from leaking components 

at onshore natural gas processing plants (40 CFR part 60, 

subpart KKK) and new source performance standards for sulfur 

dioxide emissions from natural gas processing plants (40 CFR 

part 60, subpart LLL). The EPA also established standards (40 

CFR part 60, subpart OOOO) for certain oil and gas operations 

not covered by the existing standards. In addition to the 

operations covered by subparts KKK and LLL, subpart OOOO will 

regulate volatile organic compound emissions from gas wells, 

centrifugal compressors, reciprocating compressors, pneumatic 

controllers, and storage vessels. 

For gas well affected facilities, we are finalizing 

operational standards for completions of hydraulically fractured 

gas wells. The final rule applies to three subcategories of 

fractured gas wells for which well completion operations are 

conducted: (1) wildcat (exploratory) and delineation wells; (2) 

non-wildcat and non-delineation wells for which the reservoir 

pressure is insufficient for a reduced emissions completion 

(REC), commonly referred to as a “green completion,” to be 

performed, as determined by a simple calculation involving 

reservoir pressure, well depth and gathering line pressure at 

the sales meter (we refer to these wells as “low pressure 
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wells”) and (3) all other fractured gas wells. For category (3) 

wells, each well completion operation must employ REC in 

combination with use of a completion combustion device to 

control gas not suitable for entering the gathering line. For 

category (1) wells (exploratory and delineation wells) and 

category (2) wells (low pressure wells), the final rule contains 

an operational standard that requires the use of a completion 

combustion device. However, the final rule does not prohibit the 

use of REC for completion of these wells. 

For compressor affected facilities, the final rule requires 

measures to reduce VOC emissions from centrifugal and 

reciprocating compressors. The final rule contains standards for 

wet seal centrifugal compressors located between the wellhead 

and the point at which the gas enters the transmission and 

storage segment. The final standards require 95 percent 

reduction of VOC emissions from each wet seal centrifugal 

compressor affected facility. The standard can be achieved by 

capturing and routing the emissions to a control device that 

achieves an emission reduction of 95 percent. 

The operational standards for reciprocating compressors in 

the final rule require replacement of the rod packing based on 

usage. The rod packing must be changed every 26,000 hours of 

operation. Alternatively, owners or operators can elect to 
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change the rod packing every 36 months in lieu of monitoring 

compressor operating hours. 

We are also finalizing VOC standards to reduce emissions 

from individual natural gas-driven pneumatic controllers that 

vent continuously to the atmosphere and are located between the 

wellhead and the point at which the gas enters the transmission 

and storage segment. At natural gas processing plants, the final 

rule includes a natural gas bleed rate limit of zero standard 

cubic feet per hour for each individual pneumatic controller. At 

other locations in the oil and natural gas production segment, 

the final rule includes a natural gas bleed rate limit of 6 

standard cubic feet of gas per hour for an individual pneumatic 

controller. 

The final rule contains VOC standards for new or modified 

storage vessels. The final rule, which applies to individual 

vessels, requires that storage vessels with emissions equal to 

or greater than 6 tpy achieve at least 95 percent reduction in 

VOC emissions. 

For onshore natural gas processing plants, we are revising 

the existing NSPS requirements for leak detection and repair 

(LDAR) to reflect the procedures and leak thresholds established 

by 40 CFR 60, subpart VVa.

This action also includes revisions to the national 

emission standards for hazardous air pollutants for glycol 
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dehydration unit process vents and leak detection and repair 

requirements. In the final rule, we have revised the new source 

MACT standards for “large” glycol dehydrators as well as the 

leak detection and repair requirements. In addition, pursuant to 

section 112(d)(2) and (3), we have established MACT standards 

for “small” glycol dehydrators and storage vessels that were not 

controlled under the initial NESHAP. 

In this final rule, we have established for the first time 

MACT standards for “small” glycol dehydration units, which were 

left unregulated under the initial NESHAP. This 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).

The final MACT standards for the subcategory of small 

dehydrators at oil and gas production facilities require that 

existing affected sources meet a unit-specific BTEX limit of 

3.28x10-4 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.

In the final rule, we have also established for the first 

time MACT standards for certain storage vessels that were not 

previously regulated under the initial NESHAP. The standard is 
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the same as that promulgated in the initial NESHAP for the other 

storage vessels (i.e., 95 percent emission reduction). 

In the subpart HH final rule, as a result of our review 

under section 112(d)(6), we are revising the leak definition for 

valves to 500 ppm, thus requiring the application of the leak 

detection and repair requirement at this lower detection level. 

This leak definition applies only to valves and not other 

components.

In the subpart HHH final rule, as a result of our review 

under section 112(d)(6), we have revised the new source MACT 

standards for “large” glycol dehydrators. In addition, pursuant 

to section 112(d)(2) and (3), we have established MACT standards 

for “small” glycol dehydrators that were not controlled under 

the initial NESHAP. 

In this final rule, we have established for the first time 

MACT standards for “small” glycol dehydration units in the 

Natural Gas Transmission and Storage source category. This 

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 final MACT standard for this subcategory of small 

dehydrators requires existing affected sources to meet a unitspecific BTEX emission limit of 3.01 x 10-4 grams BTEX/scm-ppmv 
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and new affected sources are required to meet a BTEX limit of 

5.44 x 10-5 grams BTEX/scm-ppmv.

3. Costs and Benefits

The estimated total capital cost to comply with the final 

amendments to 40 CFR part 63, subpart HH for major sources in 

the Oil and Natural Gas Production source category is 

approximately $47 million. The total capital cost for the final 

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 final amendments to 40 CFR part 63, subpart HH for 

major sources in the Oil and Natural Gas Production source 

category is approximately $18 million. The total net annual cost 

for final 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. All costs 

are in 2008 dollars.

The estimated total capital cost to comply with the final 

NSPS is approximately $340 million in 2008 dollars. The total 

estimated net annual cost to industry to comply with the final 

NSPS is approximately $340 million in 2008 dollars. 
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The final 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 final rules combined are anticipated to reduce 

20,000 tons of HAP, 300,000 tons of VOC (a precursor to both 

PM2.5 and ozone formation) and 1.7 million tons of methane (a GHG 

and a precursor to global ozone formation). 

B. Does this action apply to me?

The regulated categories and entities potentially affected

by the final standards are shown in Table 1 of this preamble.

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 is meant 

to provide a guide for readers regarding entities likely to be 

affected by this action. If you have any questions regarding the 
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applicability of this action to a particular entity, consult 

either the air permitting authority for the entity or your EPA 

regional representative as listed in 40 CFR 60.4 or 40 CFR 63.13 

(General Provisions).

C. What are the emission sources affected by this action?

1. What are the emission sources affected by the NSPS?

The emission sources affected by the NSPS include well 

completions, pneumatic controllers, equipment leaks from natural 

gas processing plants, sweetening units at natural gas 

processing plants, reciprocating compressors, centrifugal 

compressors, and storage vessels. Well completions subject to 

the NSPS are limited to the flowback period following hydraulic 

fracturing operations at a gas well affected facility. 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. Pneumatic controllers affected by the NSPS include 

continuous bleed natural gas-driven pneumatic controllers 

(including replacement of an existing device). The NSPS applies 

to centrifugal compressors with wet seals and reciprocating 

compressors located in the oil and natural gas production and 

processing segments. The NSPS also applies to equipment leaks

from onshore natural gas processing plants and new or modified 

storage vessels located in all of the oil and natural gas 
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segments. The NSPS also affects sweetening units located onshore 

that process natural gas from onshore or offshore wells.

2. What are the emission sources affected by the NESHAP?

The emission sources that are affected by the Oil and 

Natural Gas Production NESHAP (subpart HH) and the Natural Gas 

Transmission and Storage NESHAP (subpart HHH) include glycol 

dehydrators, equipment leaks and storage vessels. 

D. Where can I get a copy of this document?

In addition to being available in the docket, an electronic 

copy of this action will also be available on the Worldwide Web 

(WWW). Following signature by the Administrator, a copy of the 

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) Web site 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 were used as 

inputs to the risk assessments. 

E. Judicial Review

Under CAA section 307(b)(1), judicial review of this final

rule is available only by filing a petition for review in the 

U.S. Court of Appeals for the District of Columbia Circuit by 

[INSERT DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. 
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Under CAA section 307(d)(7)(B), only an objection to this final 

rule that was raised with reasonable specificity during the 

period for public comment (including any public hearing) can be 

raised during judicial review. This section also provides a 

mechanism for the EPA to convene a proceeding for 

reconsideration “[i]f the person raising an objection can 

demonstrate to the Administrator that it was impracticable to 

raise such objection within [the period for public comment] or 

if the grounds for such objection arose after the period for 

public comment (but within the time specified for judicial 

review) and if such objection is of central relevance to the 

outcome of the rule[.]” Any person seeking to make such a 

demonstration to us should submit a Petition for Reconsideration 

to the Office of the Administrator, Environmental Protection

Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave.,

NW., Washington, D.C. 20004, with a copy to the person listed in 

the preceding FOR FURTHER INFORMATION CONTACT section, and the 

Associate General Counsel for the Air and Radiation Law Office, 

Office of General Counsel (Mail Code 2344A), Environmental 

Protection Agency, 1200 Pennsylvania Ave., NW, Washington, D.C. 

20004. Note, under CAA section 307(b)(2), the requirements 

established by this final rule may not be challenged separately 

in any civil or criminal proceedings brought by the EPA to 

enforce these requirements.
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III. Background Information on the NESHAP and NSPS

A. What are the statutory authorities for the NSPS and NESHAP?

1. What is the statutory authority for the 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. Whereas CAA section 112 standards are issued 

for new and existing stationary sources, standards of 

performance are issued for new and modified stationary sources. 

These standards are referred 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. However, the Administrator need not review any such 

standard if 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 
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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 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 ratebased 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 
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enforce a standard of performance. Typically, sources remain 

free to elect whatever control measures that they choose to meet 

the emission limits. Upon promulgation, an NSPS becomes a 

national standard to which all new, modified or reconstructed 

sources must comply.

2. What is the statutory authority for the NESHAP?

Section 112 of the CAA establishes a two-stage regulatory 

process to address emissions of 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 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 set to reflect application of measures, 

processes, methods, systems or techniques, including, but not 

limited to, measures which, (1) reduce the volume of or 
Page 28 of 497

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). A 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 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 best-controlled similar source. The 

MACT floors for existing sources can be less stringent than 

floors for new sources but cannot be less stringent than the 
Page 29 of 497

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.

The EPA is then required to review these technology-based 

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 
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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 emissions 

standards provide an ample margin of safety to protect public 

health. Section 112(f)(2) expressly preserves our use of a twostep 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 must be set 

(unless a more stringent standard is required to prevent an 

adverse environmental effect, taking into consideration costs, 

energy, safety, and other relevant factors).

If the MACT standards for HAP that are “classified as a 

known, probable, or possible human carcinogen do not reduce 

lifetime excess cancer risks to the individual most exposed to 
Page 31 of 497

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.”) As mentioned, 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.

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 has

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

is a reasonable one. See NRDC v. EPA, 529 F.3d at 1083 

 

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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(“[S]ubsection 112(f)(2)(B) expressly incorporates the EPA’s 

interpretation of the Clean Air Act from the Benzene standard, 

complete with a citation to the Federal Register”). 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.

The Agency also stated in the Residual Risk Report to Congress

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 
Page 33 of 497

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 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 
Page 34 of 497

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 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 
Page 35 of 497

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 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 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). See 54 FR 38046.
Page 36 of 497

B. What is the litigation history?

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 that, as modified, requires the EPA to 

sign by July 28, 2011,2 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 April 3, 

2012.

C. What is the sector-based approach?

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. 

 

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

parties filed with the Court a written stipulation to extend the proposal 

date from January 31, 2011, to July 28, 2011, and the final action date from 

November 30, 2011, to February 28, 2012. On October 28, 2011, pursuant to 

paragraph 10(a) of the Consent Decree, the parties filed with the Court a 

written stipulation to extend the final action date from February 28, 2012, 

to April 3, 2012. 
Page 37 of 497

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 sector-based 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 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.
Page 38 of 497

As a result of the sector-based approach, this rulemaking 

will reduce conflicting and redundant requirements. Also, the

sector-based approach facilitates 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.

D. What are the health effects of pollutants emitted from the 

oil and natural gas sector?

The final oil and natural gas sector NSPS and NESHAP 

amendments are expected to result in significant reductions in 

existing emissions and prevent new emissions from expansions of 

the industry. These emissions include HAP, VOC (a precursor to 

both PM2.5 and ozone formation), and methane (a GHG and a 

precursor to global ozone formation). These emissions are 

associated with substantial health effects, welfare effects and 

climate effects. One HAP of particular concern from the oil and 

natural gas sector is benzene, which is a known human 

carcinogen. PM2.5 is associated with health effects including

premature mortality for adults and infants, cardiovascular 

morbidity, such as heart attacks, hospital admissions and 

respiratory morbidity such as asthma attacks, acute and chronic 
Page 39 of 497

bronchitis, hospital and emergency room visits, work loss days, 

restricted activity days and respiratory symptoms, as well as 

visibility impairment. Ozone is associated with health effects, 

including hospital and emergency department visits, school loss 

days and premature mortality, as well as injury to vegetation 

and climate effects.

IV. Summary of the Final NSPS Rule

A. What are the final actions relative to the NSPS for the Crude 

Oil and Natural Gas source category?

We are revising the existing NSPS, which regulate VOC 

emissions from equipment leaks and SO2 emissions from sweetening 

units at onshore gas processing plants. In addition, we are 

promulgating standards for several new oil and natural gas 

affected facilities. The final standards apply to affected 

facilities that commence construction, reconstruction or 

modification after August 23, 2011, the date of the proposed 

rule. 

The listed oil and gas source category covers all 

operations in this industry (production, processing, 

transmission, storage, and distribution), including those for 

which we are establishing standards in this final rule. To the 

extent there are operations not covered by the currently listed 

category, pursuant to section 111(b), we have modified the list 

to include all operations in this industry as mentioned above.
Page 40 of 497

1. Standards for gas well affected facilities

We are finalizing operational standards for completions of 

hydraulically fractured gas wells. For purposes of this rule, 

well completion is defined as the flowback period beginning 

after hydraulic fracturing and ending with either well shut in 

or continuous flow of gas to the sales line, whichever occurs 

first. The final rule applies to three subcategories of 

fractured gas wells for which well completion operations are 

conducted: (1) wildcat (exploratory) and delineation wells; (2) 

non-wildcat and non-delineation wells for which the reservoir 

pressure is insufficient for a reduced emissions completion

(REC), commonly referred to as a “green completion,” to be 

performed, as determined by a simple calculation involving 

reservoir pressure, well depth and gathering line pressure at 

the sales meter (we refer to these wells as “low pressure 

wells”) and (3) all other fractured gas wells. For category (3) 

wells, each well completion operation begun on or after [INSERT 

DATE TWO YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], must employ REC in combination with use of a 

completion combustion device to control gas not suitable for 

entering the gathering line. For well completion operations 

begun prior to [INSERT DATE TWO YEARS AFTER DATE OF PUBLICATION 

IN THE FEDERAL REGISTER] at category (3) wells, the final rule 

requires the control of emissions either using REC or a 
Page 41 of 497

completion combustion device. Owners and operators are 

encouraged to use REC during this period if possible.

For category (1) wells (exploratory and delineation wells)

and category (2) wells (low pressure wells), the final rule 

contains an operational standard that requires the use of a 

completion combustion device. However, the final rule does not 

prohibit the use of REC for completion of these wells.

Well completions subject to the standards are 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 completion operations associated 

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

existing prior to August 23, 2011) is considered a modification 

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

existing well resulting in emissions increases during the 

refracturing and completion operation. Therefore, the final 

standards apply to completions at new gas wells that are 

fractured or refractured as well as completions associated with 

fracturing or refracturing of existing gas wells. The 

modification determination and resulting applicability of NSPS 

to the completion operation following fracturing or refracturing 

of existing gas wells (i.e., wells existing before August 23, 
Page 42 of 497

2011), is limited strictly to the wellhead, well bore, casing 

and tubing, and any conveyance through which gas is vented to 

the atmosphere. It does not extend 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. 

2. Standards for compressor affected facilities

The final rule requires measures to reduce VOC emissions 

from centrifugal and reciprocating compressors. The final rule 

contains standards for wet seal centrifugal compressors located 

between the wellhead and the point at which the gas enters the 

transmission and storage segment. Compressors located in the 

transmission and storage segment are not affected facilities.

The final standards require 95 percent reduction of the 

emissions from each wet seal centrifugal compressor affected 

facility. The standard can be achieved by capturing and routing 

the emissions to a control device that achieves an emission 

reduction of 95 percent. 

The operational standards for reciprocating compressors in 

the final rule require replacement of the rod packing based on 

usage. The owner or operator of a reciprocating compressor 

affected facility is required to monitor the duration (in hours) 

that the compressor is operated, beginning on the date of 

initial startup of the reciprocating compressor affected 
Page 43 of 497

facility, or on [INSERT DATE 60 DAYS FOLLOWING DATE OF 

PUBLICATION IN THE FEDERAL REGISTER], or on the date of the 

previous packing rod replacement, whichever is later. When the 

hours of operation reach 26,000 hours (equivalent to 36 months 

of continuous usage), the owner or operator is required to 

change the rod packing immediately. Alternatively, owners or 

operators can elect to change the rod packing every 36 months in 

lieu of monitoring compressor operating hours.

3. Standards for pneumatic controller affected facilities

We are also finalizing VOC standards to reduce emissions 

from individual natural gas-driven pneumatic controllers that 

vent continuously to the atmosphere and are located between the 

wellhead and the point at which the gas enters the transmission 

and storage segment. Pneumatic controllers located in the 

transmission and storage segment and distribution segments are 

not affected facilities. Each continuous bleed, natural gas 

driven pneumatic device is an affected facility. Accordingly, 

the final standards apply to each newly installed pneumatic 

controller (including replacement of an existing controller). At 

natural gas processing plants, the final rule includes a natural 

gas bleed rate limit of zero standard cubic feet per hour for 

each individual pneumatic controller. The final emission 

standards for pneumatic controllers at natural gas processing 

plants reflect the emission level achievable from the use of 
Page 44 of 497

non-natural gas-driven pneumatic controllers. At other locations

in the oil and natural gas production segment, the final rule 

includes a natural gas bleed rate 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 natural gas-driven pneumatic controllers. In both cases, 

the standards provide exemptions for certain critical 

applications based on functional considerations.

4. Standards for storage vessels

The final rule contains VOC standards for new or modified 

storage vessels. The final rule, which applies to individual 

vessels, requires that storage vessels with emissions equal to 

or greater than 6 tpy achieve at least 95-percent reduction in 

VOC emissions. For storage vessels installed at well sites with 

no wells already in production at the time of installation, or 

in situations where a storage vessel currently emitting less 

than 6 tpy experiences an increase in throughput due to an 

additional well coming on line or other factor, the final rule 

provides a 30-day period for the owner or operator to determine 

whether the magnitude of VOC emissions from the storage vessel 

will be at least 6 tpy. If the storage vessel requires control, 

the final rule provides an additional 30 days for the control 

device to be installed and operational. For well sites with one 

or more wells already in production at the time of installation, 
Page 45 of 497

or in situations where an existing storage vessel is replaced, 

these estimation and installation periods are not provided.

5. Standards for affected facilities located at onshore natural 

gas processing plants

For onshore natural gas processing plants, we are revising 

the existing NSPS requirements for leak detection and repair 

(LDAR) to reflect the procedures and leak thresholds established 

by 40 CFR 60, subpart VVa.

6. Standards for sweetening unit affected facilities at onshore 

natural gas processing plants

The final rule is a revision to the current standard, which 

regulates SO2 emissions from natural gas processing plants by

requiring affected facilities to reduce SO2 emissions by 

recovering sulfur. 

B. What are the effective and compliance dates for the final 

NSPS?

The revisions to the NSPS standards being promulgated in 

this action are effective on [INSERT DATE 60 DAYS AFTER DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. Affected facilities must 

be in compliance with the final standards on the effective date,

[INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL 

REGISTER].

V. Summary of the Significant Changes to the NSPS since Proposal
Page 46 of 497

The previous section described the requirements that the

EPA is finalizing in this rule. This section will discuss in 

greater detail the key changes the EPA is making from the 

proposal. These changes result from the EPA’s review of the 

additional data and information provided to us and our 

consideration of the many substantive and thoughtful comments 

submitted on the proposal.

While our approach and methodology to establishing the standards

remain the same, the changes make the final rule more flexible

and cost-effective, address concerns with equipment 

availability, streamline recordkeeping and reporting 

requirements, and improve clarity, while fully preserving or 

improving the public health and environmental protection 

required by the CAA.

A. Gas well affected facilities

In the final rule, we are revising the requirements for gas 

well affected facilities. In the proposed subpart OOOO, the rule 

requirements applied to gas well affected facilities that 

commenced construction, modification or reconstruction after 

August 23, 2011. Because of uncertainties in the supply of 

equipment and labor over the near-term we are now requiring RECs 

for completion operations begun at category (3) wells (nonexploratory and non-delineation wells) on or after [INSERT DATE 

TWO YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER].
Page 47 of 497

Until this date, flowback emissions must either be controlled 

using REC or routed to a completion combustion device unless it 

is technically infeasible or unsafe to do so. Owners and 

operators are encouraged to use REC during this period if 

possible. Completion operations at category (1) wells (wildcat 

and delineation wells) and category (2) wells (non-wildcat and 

non-delineation low pressure wells) begun on or after [INSERT 

DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]

are required to perform REC in combination with a completion 

combustion device unless it is technically infeasible or unsafe 

to do so. 

Additionally, we are finalizing our proposed definition of 

modification as it pertains to well completion operations 

following fracturing or refracturing. The final rule provides 

clarification of what we consider to be a modification for gas 

well affected facilities by specifying that well completion 

operations following hydraulic fracturing or refracturing at gas 

well facilities in existence before August 23, 2011 are 

considered modifications with respect to the gas well affected 

facility and are therefore subject to the requirements of the 

NSPS.

In the proposed rule, we prescribed specific equipment to 

accomplish an REC. For the final rule, we have removed the 

required equipment specifications for RECs. 
Page 48 of 497

Initial compliance requirements for gas well affected 

facilities have also been revised. Owners and operators are now 

required to notify the Administrator by the first of each month 

of all anticipated well completion operations during that month, 

rather than the proposed requirement of notifying the

Administrator of the date of the well completion operation 

within 30 days of the commencement of each well completion 

operation. We have also added a requirement that the owner or 

operator notify the Administrator of the actual date of each

well completion operation by email not earlier than 3 days or 

later than 2 days prior to the well completion operation.

In the final rule, we have also added a recordkeeping 

requirement for each gas well facility for which an exemption 

from combustion requirements is claimed. Owners and operators 

are now required to record the location of the well; the 

specific exemption claimed; the starting and ending date of the 

period the well operated under the exemption; and an explanation 

of why the well meets the claimed exemption.

Refer to section IX.B of this preamble and the Responses to 

Comments document, available in the docket, for detailed 

discussion regarding these changes.

B. Centrifugal and reciprocating compressor affected facilities

In the final rule in response to comments requesting 

clarification, we have made changes that impact both 
Page 49 of 497

reciprocating and centrifugal compressors affected facilities. 

We have clarified that the NSPS does not apply to centrifugal 

and reciprocating compressors located in the natural gas 

transmission and storage segment. 

We are not requiring that all centrifugal compressors use 

dry seals, as we proposed, due to technical infeasibility of 

using dry seals for certain applications. Instead, we are 

requiring that centrifugal compressors with wet seals reduce 

emissions by 95 percent. Centrifugal compressors with dry seals 

are not affected facilities. The standard can be achieved by 

capturing and routing emissions from the wet seal fluid 

degassing system to a control device that reduces VOC emissions 

by 95 percent. Testing, monitoring, recordkeeping, reporting and 

notification requirements associated with the control devices 

have also been added. 

As proposed, owners or operators of reciprocating 

compressor affected facilities were required to change rod 

packing after 26,000 hours of operation. This is equivalent to 

approximately 36 months of continuous operation. Based on 

comments we received, we are changing the final rule to provide 

operators the option of changing the rod packing every 36 months 

instead of tracking compressor hours of operation.
Page 50 of 497

Refer to section IX.D of this preamble and the Responses to 

Comments document, available in the docket, for detailed 

discussion regarding these changes.

C. Pneumatic controller affected facilities

For pneumatic controller affected facilities, we have 

revised the definition of pneumatic controller affected facility 

from a single pneumatic controller to a single natural gasoperated pneumatic controller that vents continuously to the 

atmosphere. As explained further in section IX.C of this 

preamble, this change provides clarity by more specifically 

defining the pneumatic controllers we intended to be regulated 

by the final rule. In addition, only pneumatic controllers 

located prior to the point at which the gas enters the 

transmission and storage segment are subject to the NSPS.

Controllers located in the transmission and storage segment are 

not affected facilities.

In the proposed rule, a pneumatic controller affected 

facility installed after August 23, 2011 was subject to the 

requirements. The final rule now applies to pneumatic controller 

affected facilities installed after [INSERT DATE OF PUBLICATION 

IN THE FEDERAL REGISTER]. All new, modified, and reconstructed 

pneumatic controllers are required, in the final rule, to be 

tagged with the month and year of installation and
Page 51 of 497

identification that allows traceability to the records for that 

controller.

Finally, in order to streamline the recordkeeping and 

reporting requirements associated with pneumatic controllers, we 

are requiring only information on those affected facilities 

installed during the reporting period to be included in the 

annual report.

Refer to section IX.C of this preamble and the Responses to 

Comments document, available in the docket, for detailed 

discussion regarding these changes.

D. Storage vessel affected facilities

We have modified the definition of “storage vessel” to 

exclude surge control vessels, knockout vessels and pressure 

vessels designed to operate without emissions to the atmosphere. 

In addition, we have clarified that we consider a storage vessel 

that is skid-mounted or permanently attached to a motor vehicle 

(such as trucks, railcars, barges or ships) to be stationary 

once it is located at a site for at least 180 days.

In the proposed rule, we established a throughput threshold

for storage vessels, below which they were not subject to the 

NSPS. In order to remove confusion with respect to the emission 

factors used to develop the throughput threshold and to address 

comments indicating significant difficulty measuring throughput, 

we have revised the final rule such that storage vessels that
Page 52 of 497

emit less than 6 tpy of VOC are not required to be controlled. 

In the final rule, for storage vessels installed at well sites 

with no wells already in production at the time of installation, 

or in situations where a storage vessel currently emitting less 

than 6 tpy experiences an increase in throughput due to an 

additional well coming on line or other factor, the final rule 

provides a 30-day period for the owner or operator to determine 

whether the magnitude of VOC emissions from the storage vessel 

will be at least 6 tpy. If the storage vessel requires control, 

the final rule provides an additional 30 days for the control 

device to be installed and operational. For well sites with one 

or more wells already in production at the time of installation, 

or in situations where an existing storage vessel is replaced, 

these estimation and installation periods are not provided.

Several requirements for storage vessels in the proposed 

rule pointed to 40 CFR part 63, subpart HH (the oil and natural 

gas production NESHAP). However, subpart HH regulates HAP while

this NSPS regulates VOC. Therefore, in order to eliminate 

confusion caused by cross-referencing another regulation and to 

tailor the requirements for VOC regulation, we have incorporated 

the storage vessel requirements from subpart HH into subpart 

OOOO and modified those requirements as appropriate for this 

rule. 
Page 53 of 497

Refer to section IX.E of this preamble and the Responses to 

Comments document, available in the docket, for detailed 

discussion regarding these changes.

E. Equipment leaks affected facilities and sweetening unit 

affected facilities at onshore natural gas processing plant 

affected facilities

We have not made any changes since proposal to the 

requirements for affected facilities and sweetening unit 

affected facilities at onshore natural gas processing plants for 

the final rule. Refer to section IX.F of this preamble and the 

Responses to Comments document, available in the docket, for 

detailed discussion regarding these affected facilities.

F. Changes to notification, recordkeeping and reporting 

requirements

We have analyzed the notification, recordkeeping and 

reporting requirements throughout the proposed rule and 

eliminated duplicative and unnecessary requirements for all 

emission points. For well completions, compressors, pneumatic 

controllers and storage vessels we have removed the General 

Provisions notification requirements under section 60.7(a)(1),

(3) and (4).

In the affirmative defense provisions of the rule, a 

citation was corrected, minor wording changes were made, and 

reporting requirements were refined. The provisions we retained 
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in the final rule are those we believe are necessary to assure 

regulatory agencies and the public that the owner or operator is 

in compliance with the final rule. Refer to section IX.G of this 

preamble and the Responses to Comments document, available in 

the docket, for detailed discussion regarding these changes.

VI. Summary of the Final NESHAP Rules

A. What are the final rule amendments for the Oil and Natural 

Gas Production Facilities (subpart HH) source category?

Pursuant to section 112(d)(2) and (3), we have established 

MACT standards for “small” glycol dehydrators and storage 

vessels that were not controlled under the initial NESHAP. We 

have also amended subpart HH to apply the standards at all 

times, including periods of startup, shutdown and malfunction.

Lastly, the final rule includes modification and addition of 

testing and monitoring and related notification, recordkeeping 

and reporting requirements, as well as other minor technical 

revisions to the NESHAP. Our review under section 112(f)(2) did 

not result in revision to the standards.

1. Standards for glycol dehydration unit process vents

In this final rule, we have established for the first time

MACT standards for “small” glycol dehydration units, which were 

left unregulated under the initial NESHAP. This subcategory 

consists of glycol dehydrators with an actual annual average 

natural gas flowrate less than 85,000 standard cubic meters per 
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day (scmd) or actual average benzene emissions less than 0.9 

megagrams per year (Mg/yr).

The final MACT standards for the subcategory of small 

dehydrators at oil and gas production facilities require that 

existing affected sources meet a unit-specific BTEX limit of 

3.28x10-4 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.

2. Standards for storage vessels

In the final rule, we have also established for the first 

time MACT standards for certain storage vessels that were not 

previously regulated under the initial NESHAP. The standard is 

the same as that promulgated in the initial NESHAP for the other 

storage vessels (i.e., 95 percent emission reduction). Thus, the 

storage vessel requirements will apply to all storage vessels at 

major sources, not just to those storage vessels with 

hydrocarbon liquid throughput equal to or greater than 79,500 

liters per day. In addition, we have amended 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.

3. Standards for equipment leaks
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In the final rule, as a result of our review under section 

112(d)(6), we are revising the leak definition for valves to 500 

ppm, thus requiring the application of the leak detection and 

repair requirement at this lower detection level. This leak 

definition applies only to valves and not other components.

4. Notification, recordkeeping and reporting requirements

The final rule revises certain recordkeeping requirements 

of 40 CFR part 63, subpart HH. Specifically, facilities using 

carbon adsorbers as a control device are required to 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 new MACT standards for 

small glycol dehydration units and storage vessels that do not 

have the PFE in the final amendments to 40 CFR part 63, subpart 

HH, owners and operators of affected small glycol dehydration 

units and storage vessels are required to submit an initial 

notification within 1 year after becoming subject to subpart HH 

(as revised in this final rule) or by the date of publication of 

the final rule in the Federal Register, whichever is later. 

Newly affected sources under 40 CFR part 63, subpart HH 

that plan to be area sources by the major source compliance 
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dates will be required to submit a notification describing their 

schedule for the actions planned to achieve area source status.

The final amendments to the NESHAP also include additional 

requirements for the contents of the periodic reports. The 

periodic reports are required to include periodic test results 

and information regarding any carbon replacement events that 

occurred during the reporting period.

B. What are the final rule amendments for the Natural Gas 

Transmission and Storage facilities (subpart HHH) source 

category?

Pursuant to section 112(d)(2) and (3), we have established 

MACT standards for “small” glycol dehydrators that were not 

controlled under the initial NESHAP. We have also amended 

subpart HHH to apply the standards at all times, including 

periods of startup, shutdown and malfunction. Lastly, the final 

rule includes modification and addition of testing and 

monitoring and related notification, recordkeeping and reporting 

requirements, as well as other minor technical revisions to the 

NESHAP. Our review under section 112(f)(2) did not result in 

revision to the standards.

1. Standards for glycol dehydration units

In this final rule, we have established for the first time

MACT standards for “small” glycol dehydration units in the 

Natural Gas Transmission and Storage source category. This
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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 final MACT standard for this subcategory of small 

dehydrators requires existing affected sources to meet a unitspecific BTEX emission limit of 3.01x10-4 grams BTEX/scm-ppmv and 

new affected sources are required to meet a BTEX limit of 

5.44x10-5 grams BTEX/scm-ppmv.

2. Notification, recordkeeping and reporting requirements

The final rule revises certain recordkeeping requirements 

of 40 CFR part 63, subpart HHH. Specifically, facilities using 

carbon adsorbers as a control device are required to 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 conjunction with the promulgation of the MACT standards 

for small glycol dehydration units in 40 CFR part 63, subpart 

HHH, the final rule requires that owners and operators of small 

glycol dehydration units submit an initial notification within 1 

year after becoming subject to subpart HHH or by the date of 

publication of the final rule in the Federal Register, whichever 

is later. Affected sources under 40 CFR part 63, subpart HHH 
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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 final amendments to the NESHAP also include additional 

requirements for the contents of the periodic reports. For 40 

CFR part 63, subpart HHH, the periodic reports are required to 

include periodic test results and information regarding any 

carbon replacement events that occurred during the reporting 

period.

C. What are the effective and compliance dates of the standards?

The revisions to the MACT standards being promulgated in 

this action are effective on [INSERT DATE 60 DAYS AFTER DATE OF 

PUBLICATION IN THE FEDERAL REGISTER].

The compliance date for existing small glycol dehydration 

units and storage vessels that are subject to MACT for the first 

time (i.e., those that commenced construction before August 23, 

2011) is 3 years after the date of promulgation of the 

standards, [INSERT DATE THREE YEARS AFTER THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER].

The compliance date for new affected sources (those that 

commence construction or reconstruction on or after August 23, 

2011) is immediately upon initial startup or the effective date 

of the standards, [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION 

IN THE FEDERAL REGISTER], whichever is later.
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The compliance date for production field facilities 

constructed before August 23, 2011, that were previously 

determined to be area sources but become a major sources on 

[INSERT DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE 

FEDERAL REGISTER] is 3 years after the promulgation of the 

standards [INSERT DATE THREE YEARS AFTER THE DATE OF PUBLICATION 

IN THE FEDERAL REGISTER].

VII. Summary of the Significant Changes to the NESHAP since 

Proposal

The previous section described the requirements that the 

EPA is finalizing in this rule. This section discusses in 

greater detail the key changes the EPA is making from the 

proposal. These changes result from the EPA’s review of the 

additional data and information provided to us and our 

consideration of the many substantive and thoughtful comments 

submitted on the proposal.

While our approach and methodology to establishing the 

standards remain the same, the changes modify the emission 

limits for glycol dehydration units and extend the storage 

vessel requirements to all storage tanks at major sources, while 

fully preserving, or improving, the public health and 

environmental protection required by the CAA.
Page 61 of 497

A. What are the significant changes since proposal for the Oil 

and Natural Gas Production Facilities (subpart HH) source 

category?

1. Small glycol dehydration units

In the final amendments for subpart HH, we have revised the 

proposed MACT standards for small glycol dehydration units in 

response to comments. In our proposal, the MACT standards for

existing affected sources was a unit-specific BTEX limit of 

1.10x10-4 g BTEX/scm-ppmv and for new affected sources was a BTEX 

limit of 4.66 x10-6 g BTEX/scm-ppmv. In this final rule, the BTEX 

emission limit for existing small glycol dehydration units is 

3.28x10-4 grams BTEX/standard cubic meters (scm)-parts per 

million by volume (ppmv) and for new small glycol dehydration 

units the revised BTEX limit is 4.66 x10-6 grams BTEX/scm-ppmv.

2. Large glycol dehydration unit 0.9 Mg/yr benzene compliance 

alternative

We had proposed to eliminate the 0.9 Mg/yr benzene 

compliance option for large glycol dehydration unit process 

vents. This was due to our estimate of the Maximum Individual 

Risk (MIR) allowed under the 0.9 Mg/yr benzene compliance option 

to be 400-in-1-million. Our estimates of the source category 

maximum cancer risks have changed since proposal due to 

information received during the comment period. For the two 

facilities determined to have the highest MIRs based on 
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allowable emissions, we found that the actual emissions used for 

each facility were incorrect and the multipliers used for the 

allowable calculation were too high. After correcting the 

multipliers for each facility, the MIR became 3 for the highest 

facility and less than 1 for the second highest facility.

Based on actual emissions estimates for the Oil and Natural 

Gas Production source category, the estimated MIR is now 10-in-1 

million3, compared to 40-in-1 million estimated in the proposed 

rule. We also estimate that the MIR based on the MACT-allowable 

emissions level is now 10-in-1 million, compared to 400-in-1 

million estimated in the proposed rule. The total estimated 

cancer incidence from the 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. This estimate is unchanged from the proposed rule. 

Approximately 120,000 people are estimated to have cancer risks 

at or above 1-in-1 million, compared to 160,000 people estimated 

in the proposed rule. The estimates from the proposed rule of 

maximum chronic non-cancer TOSHI value (0.1) and maximum acute 

non-cancer hazard quotient value (9, based on the benzene REL) 

 

3 Three other facilities had an MIR of 20 based on our risk assessment at 

proposal. All three were determined to be area sources for HAP based on 

discussions with the permitting authority. Area sources are not within the 

scope of our risk assessment under section 112(f)(2).
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are unchanged. Facility-wide risk estimates are also unchanged 

from the proposed rule.

In accordance with the approach established in the Benzene 

NESHAP, the EPA weighed all health risk measures and 

information, including the maximum individual cancer risk, the 

cancer incidence, the number of people exposed to a risk greater 

than 1-in-1-million, the distribution of risks in the exposed 

population, and the uncertainty of our risk calculations in 

determining whether the risk posed by emissions from oil and 

natural gas production is acceptable.

In determining whether risk is acceptable, we considered 

the available health information, as described above. In this 

case, because the MIR is less than 100-in-1-million, 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 

conclude that the risk is acceptable.

Although we have concluded that risks from this source 

category are acceptable, risk estimates for individuals in the 

exposed population are above 1-in-1-million. Consequently, we 

considered whether the MACT standards (including those 

promulgated today) provide an ample margin of safety. In this 

analysis, we investigated available emissions control options 
Page 64 of 497

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.

As stated above, after corrections, the MIR is 10-in-1 

million for the major source category. The source of the 

emissions driving this risk is a glycol dehydrator at the 

Vintage Production facility in Ventura, CA. Since the unit at 

this facility is a small glycol dehydrator (this unit has a 

design throughput of 1 MMSCFD), it will be subject to the small 

dehydrator BTEX limit in the final rule. We determined the

applicable BTEX limit for this unit under the final MACT 

provisions and determined that the resulting MIR would be less 

than 1-in-1-million. Because this unit is subject to a standard 

under the final rule, we do not consider that limit to be 

required under section 112(f)(2). Therefore, to complete our 

risk analysis, we looked at the facility with the next-highest 

MIR4. This facility has a MIR of 10-in-1 million driven by 

naphthalene emissions from fugitive sources.

We considered requiring a LDAR program to reduce fugitive 

emissions. Requiring an LDAR program equivalent to NSPS subpart 

VV would reduce HAP emissions approximately 1 percent, which 

 

4 Aera Energy LLC in Ventura, CA. 
Page 65 of 497

would equate to 0.6 tons5. The estimated annual costs for this 

option would be $97,000. The cost effectiveness would be 

$160,000 per ton of HAP reduced. 

The additional LDAR program requirement would not reduce 

the MIR for this source category based on both actual and 

allowable emissions. We consider all of these factors in our 

ample margin of safety decision and conclude that the costs of a 

LDAR program discussed above is not reasonable considering the 

emission reduction and cancer health benefits potentially 

achievable with this work practice. As a result, we are 

concluding that the MACT standards (including those promulgated 

today) provide an ample margin of safety (considering cost, 

technical feasibility, and other factors) to protect public 

health for this source category.

Based on the above corrections and analysis, we are 

retaining the 0.9 Mg/yr benzene compliance option in the final 

subpart HH amendments. Large glycol dehydration units now have 

the option of compliance with either the emission reduction 

limitation or reducing actual annual benzene emissions to less 

than 0.9 Mg/yr.

3. Other Changes

We are lowering the emission reduction allowance for 

combustion control devices that are tested under, and pass, the 

 

5 Total HAP and naphthalene emissions are approximately 64 tons and 9.5 tons, 

respectively. 
Page 66 of 497

manufacturers performance test, from 98.0 percent to 95.0 

percent. This change is a result of comments and data provided 

on the actual performance of these devices in the field. 

Consistent with the changes in the proposed rule to address 

SSM, we are removing the monitoring and reporting provisions 

related to excursions from the final rule.

No significant changes since proposal were made to the 

storage vessel and equipment leak standards.

Refer to sections X.C and X.D of this preamble and the 

Reponses to Comments document, available in the docket, for 

detailed discussion regarding these changes.

B. What are the significant changes since proposal for the 

Natural Gas Transmission and Storage facilities (subpart HHH) 

source category?

1. Small glycol dehydration units

In the final amendments for subpart HHH, we have revised 

the proposed BTEX limits for small glycol dehydration units in 

response to comments. We had proposed a unit-specific BTEX 

emission limit of 6.42x10-5 grams BTEX/scm-ppmv for existing 

sources and a BTEX limit of 1.10x10-

5 g BTEX/scm-ppmv for new 

sources. In the final rule, the MACT standards for existing 

small glycol dehydration units is an emission limit of 3.10x10-4

g BTEX/scm-ppmv and for new affected sources is a BTEX limit of 

5.44x10-5 grams BTEX/scm-ppmv.
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2. Large glycol dehydration unit 0.9 Mg/yr benzene compliance 

alternative

We had proposed to eliminate the 0.9 Mg/yr compliance 

option for large glycol dehydration unit process vents. This was 

due to our estimate of the MIR allowed under the 0.9 Mg/yr 

benzene compliance option to be 90-in-1-million. Our estimates 

of the source category maximum cancer risks have changed since 

proposal due to information received during the comment period. 

We re-examined our risk assessment and determined that the two 

facilities6 that we identified as the risk drivers at proposal 

are area sources of HAP and not part of this major source 

category that is the subject of the section 112(f)(2) review.

Based on actual emissions estimates for the Natural Gas 

Transmission and Storage source category, the estimated MIR is 

now 20-in-1 million (5-in-1 million based on the lower end of 

the benzene URE range), compared to 90-in-1 million estimated in 

the proposed rule. We also estimate that the MIR based on the 

MACT-allowable emissions levels is now 20-in-1 million (5-in-1 

million based on the lower end of the benzene URE range) 

compared to 90-in-1 million estimated in the proposed rule. The 

total estimated cancer incidence from the source category is 

0.001 excess cancer cases per year (0.003 excess cancer cases 

per year based on the lower end of the benzene URE range), or 

 

6 Bradley and Danville Compressor Stations. Both in West Virginia.
Page 68 of 497

one case in every 1000 years. This estimate is unchanged from 

the proposed rule. Approximately 2,200 people are estimated to 

have cancer risks at or above 1-in-1 million, compared to 2,500 

people estimated in the proposed rule. The maximum chronic noncancer TOSHI value is now estimated to be 0.06, compared to 0.4 

in the proposed rule. The maximum acute non-cancer hazard 

quotient value is now estimated to be 4 (based on the benzene 

REL), compared to 5 in the proposed rule (also based on the 

benzene REL). Facility-wide risk estimates are unchanged from 

the proposed rule. These corrections to the risk assessment do 

not change our overall judgment of risk acceptability.

Although we have concluded that risks from this source 

category are acceptable, risk estimates for individuals in the 

exposed population are above 1-in-1-million. Consequently, we 

considered whether the MACT standards (including those 

promulgated today) provide 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.

As stated above, after corrections, the MIR is 20-in-1 

million for the major source category. The source of the 

emissions driving this risk at this facility is fugitive 
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emissions. As we explained in the proposal preamble, under the 

ample margin of safety analysis, we investigate available 

emissions control options that may 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. 

We considered requiring a LDAR program to reduce fugitive 

emissions, which our revised assessment identifies as the risk 

driver for this source category. Requiring an LDAR program 

equivalent to NSPS subpart VV would reduce emissions 

approximately 1 percent, which would equate to 0.2 tons7. The 

estimated annual costs for this option would be $97,000. The 

cost effectiveness would be $485,000 per ton of HAP reduced.

The additional LDAR program requirement would not reduce 

the MIR for this source category based on both actual and 

allowable emissions. Considering the factors discussed above 

regarding acceptable risk, we conclude that the costs of a LDAR 

program discussed above are not reasonable considering the 

emission reductions potentially achievable with this work 

practice. As a result, we are concluding that the MACT standards 

(including those promulgated today) provide an ample margin of 

safety (considering cost, technical feasibility, and other 

factors) to protect public health for this source category.

 

7 We speciated facility VOC emissions into HAP and we estimate site-wide 

fugitive emissions to be 18 tons per year.
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Based on the above corrections and analysis, we are 

retaining the 0.9 Mg/yr benzene compliance option in the final 

subpart HHH amendments. Large glycol dehydration units now have 

the option of compliance with either the emission reduction

limitation or reducing actual annual benzene emissions to less 

than 0.9 Mg/yr.

3. Other Changes

We are lowering the emission reduction allowance for 

combustion control devices that are tested under, and pass, the 

manufacturer’s performance test, from 98.0 percent to 95.0 

percent, as a result of comments and data provided on the actual 

performance of these devices in the field. Consistent with the 

changes in the proposed rule to address SSM, we are removing the 

monitoring, recordkeeping and reporting provisions related to 

excursions from the final rule.

VIII. Compliance Related Issues Common to the NSPS and NESHAP

A. How do the rules address startup, shutdown and malfunction?

The United States Court of Appeals for the District of 

Columbia Circuit vacated portions of two provisions in the EPA’s 

CAA section 112 regulations governing the emissions of HAP 

during periods of startup, shutdown and malfunction (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 
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CFR 63.6(h)(1), that are 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.

As proposed in the NESHAP, we have eliminated the SSM 

exemption in this rule. Consistent with Sierra Club v. EPA, the 

EPA has established standards in both rules that apply at all 

times. We have also revised Table 3 (the NESHAP General 

Provisions table) in several respects. For example, we have 

eliminated the incorporation of the NESHAP General Provisions’ 

requirement that the source develop an SSM plan. We have also 

eliminated or revised certain NESHAP recordkeeping and reporting 

that related to the SSM exemption. The EPA has attempted to 

ensure that we have not included in the regulatory language, for 

the NSPS and NESHAP, any provisions that are inappropriate, 

unnecessary, or redundant in the absence of the SSM exemption.

In establishing the standards in both rules, the EPA has 

taken into account startup and shutdown periods and, for the 

reasons explained in Section IX for the NSPS and in Section X 

for the NESHAP, did not establish different standards for those 

periods. We believe that operations and emissions do not differ 
Page 72 of 497

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 

60.2 and 63.2). The EPA has determined that CAA section 111 and 

112 do not require that emissions that occur during periods of 

malfunction be factored into development of CAA section 111 or 

112 standards. 

Section 111 standards – See section III of the preamble for 

a detailed discussion on how the EPA sets or revises section 111 

new source performance standards (NSPS) to reflect the degree of 

emission limitation achievable through the application of the 

best system of emission reduction (BSER). 

Section 112 standards - Under section 112, emissions 

standards for new sources must be no less stringent than the 

level “achieved” by the best controlled similar source and for 

existing sources generally must be no less stringent than the 

average emission limitation “achieved” by the best performing 12 

percent of sources in the category. There is nothing in section 
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112 that directs the Agency to consider malfunctions in 

determining the level “achieved” by the best performing or best 

controlled sources when setting emission standards. Moreover, 

while the EPA accounts for variability in setting emissions 

standards consistent with the section 112 case law, nothing in 

that case law requires the Agency to consider malfunctions as 

part of that analysis. Section 112 uses the concept of “best 

controlled” and “best performing” unit in defining the level of 

stringency that section 112 performance standards must meet. 

Applying the concept of “best controlled” or “best performing” 

to a unit that is malfunctioning presents significant 

difficulties, as malfunctions are sudden and unexpected events. 

Further, accounting for malfunctions in setting NESHAP or 

NSPS standards would be difficult, if not impossible, given the 

myriad different types of malfunctions that can occur across all 

sources in the category and given the difficulties associated 

with predicting or accounting for the frequency, degree, and 

duration of various malfunctions that might occur. As such, the 

performance of units that are malfunctioning is not “reasonably” 

foreseeable. See, e.g., Sierra Club v EPA, 167 F. 3d 658, 662 

(D.C. Cir. 1999) (“[T]he EPA typically has wide latitude in 

determining the extent of data-gathering necessary to solve a 

problem. We generally defer to an agency's decision to proceed 

on the basis of imperfect scientific information, rather than to 
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‘invest the resources to conduct the perfect study.’”). See also

Weyerhaeuser Co. 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.”). In addition, 

in the NESAHP context, the goal of a best controlled or best 

performing source is to operate in such a way as to avoid 

malfunctions of the source and accounting for malfunctions could 

lead to standards that are significantly less stringent than 

levels that are achieved by a well-performing non-malfunctioning 

source. Similarly, In the NSPS context, accounting for 

malfunctions when setting standards of performance under section 

111 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 

could lead to standards that are significantly less stringent 

than levels that are achieved by a well-performing nonmalfunctioning source. The EPA’s approach to malfunctions is 
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consistent with section 112 and section 111 and is a reasonable 

interpretation of the statute.

Finally, the EPA recognizes that even equipment that is 

properly designed and maintained can sometimes fail and that 

such failure can sometimes cause a violation of the relevant 

emission standard. See, e.g., State Implementation Plans: Policy 

Regarding Excessive Emissions During Malfunctions, Startup, and 

Shutdown (Sept. 20, 1999); Policy on Excess Emissions During 

Startup, Shutdown, Maintenance, and Malfunctions (Feb. 15, 

1983). The EPA is therefore adding to the final NSPS and NESHAP 

an affirmative defense to civil penalties for violations of 

emission standards that are caused by malfunctions. See 40 CFR 

63.761 for sources subject to the 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 have added 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 
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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 NSPS standards must prove by a preponderance 

of the evidence that it has met all of the elements set forth in 

40 CFR 60.41Da (NSPS). 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 60.2 (NSPS) and 40 CFR 63.2 

(NESHAP), respectively, (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 the violation “[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, 40 CFR 63.1272 for sources subject to the natural gas 

transmission and storage facilities MACT standards, and 40 CFR 

60.5415 (h) for the Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution, and to 

prevent future malfunctions. For example, the source must prove 
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by a preponderance of the evidence that “[r]epairs were made as 

expeditiously as possible when the applicable emission standards 

were being exceeded...” and that “[a]ll possible steps were 

taken to minimize the impact of the violation 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 penalties may be assessed in 

accordance with Section 113 of the Clean Air Act (see also 40 

CFR part 22.27). 

The EPA proposed and is now finalizing an affirmative 

defense in the final NSPS and NESHAP in an attempt to balance a 

tension, inherent in many types of air regulation, to ensure 

adequate compliance while simultaneously recognizing that 

despite the most diligent of efforts, emission standards may be 

violated under circumstances beyond the control of the source. 

The EPA must establish emission standards that “limit the 

quantity, rate, or concentration of emissions of air pollutants 

on a continuous basis.” 42 U.S.C. §7602(k)(defining “emission 

limitation and emission standard”). See generally Sierra Club v. 

EPA, 551 F.3d 1019, 1021 (D.C. Cir. 2008). Thus, the EPA is 

required to ensure that section 112 emissions standards are 

continuous. The affirmative defense for malfunction events meets 
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this requirement by ensuring that even where there is a 

malfunction, the emission standard is still enforceable through 

injunctive relief. While “continuous” standards, on the one 

hand, are required, there is also case law indicating that in 

many situations it is appropriate for the EPA to account for the 

practical realities of technology. For example, in Essex 

Chemical v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), the 

D.C. Circuit acknowledged that in setting standards under CAA 

section 111 “variant provisions” such as provisions allowing for 

upsets during startup, shutdown and equipment malfunction 

“appear necessary to preserve the reasonableness of the 

standards as a whole and that the record does not support the 

‘never to be exceeded’ standard currently in force.” See also

Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973). Though intervening case law such as Sierra Club v. EPA

and the CAA 1977 amendments call into question the relevance of 

these cases today, they support the EPA’s view that a system 

that incorporates some level of flexibility is reasonable. The 

affirmative defense simply provides for a defense to civil 

penalties for violations that are proven to be beyond the 

control of the source. By incorporating an affirmative defense, 

the EPA has formalized its approach to upset events. In a Clean 

Water Act setting, the Ninth Circuit required this type of 

formalized approach when regulating “upsets beyond the control 
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of the permit holder.” Marathon Oil Co. v. EPA, 564 F.2d 1253, 

1272-73 (9th Cir. 1977); see also, Mont. Sulphur & Chem. Co. v. 

EPA, 2012 U.S. App. LEXIS 1056 (Jan 19, 2012) (rejecting 

industry argument that reliance on the affirmative defense was 

not adequate). But see Weyerhaeuser Co. v. Costle, 590 F.2d at 

1057-58 (holding that an informal approach is adequate). The 

affirmative defense provisions give the EPA the flexibility to 

both ensure that its emission standards are “continuous” as 

required by 42 U.S.C. §7602(k), and account for unplanned upsets 

and thus support the reasonableness of the standard as a whole.

Refer to preamble section IX for the NSPS, sections X.C and 

X.D for the NESHAP, and the Reponses to Comments document for 

both the NSPS and the NESHAP, available in the docket, for a 

detailed discussion regarding these changes.

B. How do the NSPS and NESHAP provide for compliance assurance?

The final rule includes various notification, recordkeeping 

and reporting requirements that we believe provide a robust 

compliance assurance program while reducing burden and 

streamlining requirements. The EPA also considered a variety of 

innovative compliance approaches that could maximize compliance 

and transparency while minimizing burden on the regulated 

community and regulators. More detailed information on public 

comments received and the EPA’s responses are included in 

sections IX and X of the preamble or in the RTC document.
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1. Notification, recordkeeping and reporting requirements

NSPS

For well completions, owners or operators are required to 

submit each month a single notification of all anticipated well 

completions for the upcoming month and provide the geographical 

coordinates of the affected wells and the estimated date of 

commencement of the flowback period immediately following 

hydrofracturing. Not earlier than 3 days or later than 2 days 

before each well completion, the owner or operator must notify 

the appropriate regulatory agency via e-mail of the impending 

completion. Records of each well completion that document how 

the completion operation was conducted are retained for 5 years. 

Annually, owners or operators of all affected facilities 

under the NSPS, including gas wells, compressors, pneumatic 

controllers, storage vessels, and gas processing plants, must 

report any deviation from the NSPS requirements and document 

periods of noncompliance during the reporting period. Each 

annual report must include a signed certification by a senior 

company official that attests to the truth, accuracy, and 

completeness of the report. For affected gas wells, the reports 

must also include certain details of each well completion 

conducted during the reporting period. For compressors, 

pneumatic controllers, and storage vessels, the annual reports 

must include certain information on all affected facilities that 
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were constructed, modified or reconstructed during the reporting 

period. 

Owners or operators who conduct certain performance tests 

on control devices must report results of those tests using the 

Electronic Reporting Tool (ERT). Further discussion of reporting 

of emissions tests is presented in Section VIII.D.

NESHAP

The final amendments to 40 CFR part 63, subparts HH and 40 

CFR part 63, subpart HHH revise certain recordkeeping 

requirements. Specifically, facilities using carbon adsorbers as 

a control device are now required to keep records of their 

carbon replacement schedule and records of each carbon 

replacement. We are requiring that owners and operators that use 

a manufacturer’s tested control device keep records of visible 

emissions readings and flowrate calculations and records of 

periods when the pilot flame is absent. The final amendments 

require records of the date of each semi-annual maintenance 

inspection be maintained. Finally, 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 conjunction with the final MACT standards for small 

glycol dehydration units and storage vessels that do not have 

the PFE in the final amendments to 40 CFR part 63, subpart HH,
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owners and operators of affected small glycol dehydration units 

and storage vessels are required to submit an initial 

notification within 1 year after becoming subject to subpart HH 

or by [INSERT DATE 1 YEAR AFTER DATE OF PUBLICATION IN THE 

FEDERAL REGISTER], whichever is later. If owners and operators 

of affected small glycol dehydration units and storage vessels 

plan to become area sources by [INSERT DATE 3 YEARS AFTER DATE 

OF PUBLICATION IN THE FEDERAL REGISTER], is required to submit 

in the initial notification a brief, nonbinding description of a 

schedule for the planned action(s) to achieve area source 

status.

Similarly, in conjunction with the final MACT standards for 

small glycol dehydration units in the final 40 CFR part 63, 

subpart HHH amendments, owners and operators of small glycol 

dehydration units are required to submit an initial notification 

within 1 year after becoming subject to subpart HHH or by 

[INSERT DATE 1 YEAR AFTER DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], whichever is later.

The final amendments to 40 CFR part 63, subpart HH and 40 

CFR part 63, subpart HHH include new requirements for the 

contents of Notification of Compliance Status Reports. The 

owners and operators are required to include an electronic copy 

of the performance test results for the manufacturer’s tested 

control device, if applicable; the predetermined carbon 
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replacement schedule for carbon adsorbers, if applicable; and 

data related to the manufacturer’s performance tests conducted 

for certain models of control devices, if compliance is being 

achieved using the manufacturer’s performance tests.

The final amendments to the NESHAP also include additional 

requirements for the contents of periodic reports. Each 

semiannual report must include a signed certification by a 

senior company official that attests to the truth, accuracy, and 

completeness of the report. For both 40 CFR part 63, subpart HH 

and 40 CFR part 63, subpart HHH, in the final amendments, 

periodic reports are required to include periodic test results 

and information regarding any carbon replacement events that 

occurred during the reporting period. Owners and operators are 

also required to include in the periodic reports, information 

regarding any excursions that occur when the inlet gas flowrate 

identified in the manufacturer’s performance test, and any 

excursions caused when visible emissions exceed the maximum 

allowable duration.

Owners or operators who conduct certain performance tests 

on control devices must report results of those tests using the 

Electronic Reporting Tool (ERT). Further discussion of reporting 

of emissions tests is presented in section VIII.C below.

2. Innovative compliance approaches
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At proposal, given the potential number and diversity of 

sources potentially affected by the NSPS and/or the NESHAP, we 

solicited comments on optional compliance tools that could 

reduce compliance burden and enhance transparency. Specifically, 

we asked for suggestions on: (1) registration of wells and 

advance notification of planned completions; (2) use of third 

party verification; and (3) electronic reporting using existing 

mechanisms. We received comments on each of the topics above and 

have presented summaries of those comments and the EPA’s 

responses in the RTC document. The commenters were generally 

opposed to third party verification. However, one suggestion was 

a voluntary random verification program, similar to one used in 

the past for gasoline marketing, where operators who 

participated in this program potentially could receive lower 

priority for enforcement inspections by regulators. Other 

suggested innovative approaches include use of social media, 

including Facebook and Twitter, plus new technologies such as 

quick response (QR) codes, to provide timely public notification 

and access to compliance records for individual wells and other 

affected facilities. Other suggestions included use of a 

centralized database for industry and public access to 

compliance information. Further discussion of these approaches 

is provided in the RTC. While we considered these suggestions, 

we did not adopt them in the final rule, for reasons explained 
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further in the RTC document. Some of these suggestions, however, 

may be useful for sources to consider in complying with the 

rule.

C. What are the requirements for submission of performance test 

data to the EPA?

The EPA must have performance test data to conduct 

effective reviews of CAA sections 111, 112 and 129 standards, as 

well as for many other purposes including compliance 

determinations, emission factor development, and annual emission 

rate determinations. In conducting these required reviews, the 

EPA has found it ineffective and time consuming, not only for 

us, but also for regulatory agencies and source owners and 

operators, 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.

In this action, as a step to increase the ease and 

efficiency of data submittal and improve data accessibility, the 

EPA is requiring the electronic submittal of select performance 

test data. Specifically, the EPA is requiring owners and 

operators of oil and natural gas production, transmission, 
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distribution, and storage facilities to submit electronic copies 

of performance test reports required by the rules covered under 

this action to the EPA’s WebFIRE database. The WebFIRE database 

was constructed to store performance test 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 mentioned above, data entry will be through an 

electronic emissions test report structure called the ERT. The 

ERT will generate an electronic report which will be submitted 

using the Compliance and Emissions Data Reporting Interface 

(CEDRI). The submitted report is submitted through the EPA’s 

Central Data Exchange (CDX) 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/index.html and CEDRI can be 

accessed through the CDX website (www.epa.gov/cdx). 

The requirement to submit performance test data 

electronically to the EPA does not create any additional 

performance testing and would apply only to those performance 

tests conducted using test methods that are supported by the 

ERT. The ERT contains a specific electronic data entry form for 

most of the commonly used the EPA reference methods. A listing 

of the pollutants and test methods supported by the ERT is 
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available at http://www.epa.gov/ttn/chief/ert/index.html. We 

believe that industry will benefit from this new electronic data 

submittal requirement. Having these data, the EPA will be able 

to develop improved emission factors, make fewer information 

requests, and promulgate better regulations. The information to 

be reported is already required for the existing test methods 

and is necessary to evaluate the conformance to the test method.

One major advantage of submitting 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 what testing 

information 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 results 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).
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State, local, and tribal agencies can also benefit from a 

more streamlined and accurate review of electronic data 

submitted to them. The ERT allows for an electronic review 

process rather than a manual data assessment making review and 

evaluation of the data and calculations easier and more 

efficient. Finally, another benefit of submitting data to 

WebFIRE electronically is that these data will greatly improve 

the overall quality of the existing and new emission 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 will 

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 will 

save industry, state, local, tribal agencies, and the EPA 

significant time, money, and effort while improving the quality 

of emission inventories and, as a result, air quality 

regulations.
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IX. Summary of Significant NSPS Comments and Responses 

For purposes of this document, the text within the comment 

summaries was provided by the commenter(s) and represents their 

opinion(s), regardless of whether the summary specifically 

indicates that the statement is from a commenter(s) (e.g., “The 

commenter states” or “The commenters assert”). The comment 

summaries do not represent the EPA’s opinion unless the response 

to the comment specifically agrees with all or a portion of the 

comment.

A. Major comments concerning applicability 

1. Activities that constitute a modification

Comment: Referring to the definition of “modification” in 

section 111(a)(4) of the CAA, one commenter asserts that a 

modification occurs only if two things happen: (1) there must be 

a “physical change or change in the method of operation”; and 

(2) the change must result in an emissions increase. 

The commenter states that in the context of the New Source 

Review program, the D.C. Circuit Court has opined that 

“Congress's use of the word ‘any’ in defining a ‘modification’

means that all types of ‘physical changes’ are covered” (New 

York v. EPA, 443 F.3d 880, 890 (D.C. Cir. 2006)) and that the 

D.C. Circuit Court has determined that “the plain language of 

the CAA indicates that Congress intended to apply NSR to changes 

that increase actual emissions instead of potential or allowable 
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emissions.” New York v. EPA, 413 F.3d 3, 40 (D.C. Cir. 2005). 

However, according to the commenter, the Supreme Court has 

concluded that the section 111 definition of modification does 

not have to have the same meaning under the NSPS and NSR

programs (Environmental Defense v. Duke Energy Corp., 127 S. Ct. 

1423, 1434 (2007)), and thus the EPA has latitude within the 

context of section 111 to implement different rules regarding 

modifications.

The commenter believes in particular that the EPA’s 

regulatory definition of “modification” under the NSPS program 

provides several categories of activities that alone, are not to 

be considered modifications, including “maintenance, repair, and 

replacement which the Administrator determines to be routine for 

a source category,” and “an increase in production rate that can 

be accomplished without a capital expenditure.” 40 CFR 60.14(e). 

The commenter believes these provisions reflect the fact that 

Congress established the NSPS program for “new” sources. 

According to the commenter, without these exclusions, even the 

most minor activities would convert an existing source into a 

“new source.” The commenter states that the premise behind 

characterizing these activities as not being “changes” is that 

they all contemplate that the plant will continue to be operated 

in a manner consistent with its original design and thus is not 

a “new” facility.
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Response: CAA section 111(b) requires that the EPA establish 

NSPS for new sources in a listed source category. Section 111(a) 

defines new sources to include sources that undergo 

modification. As the commenter notes, 111(a)(4) defines 

modification to include any physical change which increase 

emissions. We need not address the relevance of the New York v. 

EPA, 413 F.3d 3, 40 (D.C. Cir. 2005) or Environmental Defense v. 

Duke Energy Corp., 127 S. Ct. 1423, 1434 (2007) in this package 

or whether those decision compel the position we are taking with 

respect to recompletions.

To be clear, we do not in this package question the general 

appropriateness of the NSPS general provisions at 40 CFR 

60.14(e), including our prior identification of activities that 

the EPA generally does not consider to be “modification” for 

purposes of establishing NSPS. As the commenter notes, 60.14(e) 

is intended to exclude routine and minor activities, such as 

routine maintenance and repair or an activity that requires 

insignificant expenditure. See, e.g., 40 CFR 60.14(e)(1) and 

(2). 

However, as the general provisions themselves recognize, 

the general NSPS definition of modification may not be 

appropriate in all cases. Specifically, the General Provision at 

40 CFR 60.14(f) allows the EPA to promulgate special provisions 

in any specific subpart to supersede any conflicting 
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modification provision in 60.14(e). Well completions involving 

hydraulic fracturing are not the kind of minor or routine 

activities that the EPA had intended to exclude when it 

promulgated section 60.14(e), which more appropriately address 

the minor activities in typical stationary sources, such as a 

plant or a facility. 

As explained in the proposal, recompletions fit well within 

the statutory definition of modification (the fracturing results 

in a physical change which causes flowback and an increase in 

emissions relative to the emissions level prior to the 

refracturing). Given the significant, although short term, 

increase in emissions and the cost effective nature of the 

control on such emissions, we have concluded that coverage of 

refracturing activities is appropriate even if it requires 

departing from the General Provision definition of modification.

We note that the EPA learned from the comment that some 

hydraulic fracturing operations may be excluded under 

60.14(e)(2) because their expenditures do not meet the 

regulatory definition of “capital expenditure.” Pursuant to 

60.14(f) and for the reasons described above, the EPA is adding 

a special provision in NSPS subpart OOOO that modification 

occurs when a fractured or refractured well undergoes a

completion and clarifying that this specific provision 

supercedes any conflicting modification provisions in 60.14(e). 
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We consider this change to be a logical outgrowth of the 

proposal as our description and analysis evidenced a clear 

intent to cover all such activities.

2. Regulation of methane and other pollutants

Comment: One commenter believes that under section 111, the EPA 

must regulate each dangerous pollutant emitted by sources in the 

oil and gas source category in more than de minimis quantities 

for which controls are available and asserts that the EPA has 

failed to do so. In particular, the commenter states that the 

EPA must regulate methane, particulate matter, hydrogen sulfide, 

and nitrogen oxides from oil and gas operations. The commenter 

states that the EPA’s explanation of why it declined to regulate 

certain pollutants does not discuss particulate matter or 

hydrogen sulfide, address the most important sources of nitrogen 

oxides, or offer a legal justification for its failure to 

regulate methane. The commenter interprets the CAA to mean that 

the EPA must, every eight years, (1) review its standards (as it 

has done here), (2) determine whether it is “appropriate” to 

revise them, including whether it is appropriate to add 

additional pollutants to the standards, and (3) if so, revise 

them accordingly.

Response: Section 111 of the CAA does not require that the EPA 

assess every single pollutant in a listed source category when 

promulgating NSPS or performing the subsequent 8-year review. 
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Section 111(a)(1) requires that the standard of performance 

reflect the application of the best system of emission 

reductions which, taking into consideration the cost of 

achieving such emission reductions, any non-air quality health 

and environmental impact and energy requirements, the 

Administrator determines has been adequately demonstrated. It 

does not require that the standard address every single 

pollutant. As implemented over many years by the EPA, the NSPS 

program has established standards that do not necessarily set 

emission limits for all pollutants or even all regulated 

pollutants emitted by sources within the relevant source 

category. Instead, the NSPS generally focus on specific 

pollutants of concern for a particular source category. For 

instance, the NSPS promulgated for the oil and gas category 

regulate VOC and SO2 emissions at processing plants. 

Section 111(b)(1)(B) requires that the EPA review and, “if 

appropriate,” revise, NSPS at least every eight years unless the 

Agency determines that such review is not appropriate in light 

of readily available information on the efficacy of the 

standard. Pursuant to this provision, the EPA periodically 

reviews and revises the standards of performance, as 

appropriate, to reflect improvements in methods for reducing 

emissions. The EPA also believes that it has discretion under 

section 111(b)(1)(A) to revise an NSPS to add standards for 
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pollutants not previously regulated for that source category. 

However nothing section 111(b)(1)(A) suggests that it imposes 

such duty on the EPA.

Specifically, the definitions of “stationary source” and 

“modification” do not require that the EPA assess and regulate 

every pollutant, as the commenter contended. The definition of 

“stationary source,” which refers to sources that emit or may 

emit any pollutant, simply indicates that any source that emits 

a pollutant may be subject to listing under section 111. 

Similarly, the definition of modification, which refers to 

change that results in increase of the amount of any pollutant 

or emission of pollutant not previously emitted, simply means 

that such activity could trigger NSPS applicability for an 

existing source. Neither provision addresses how the EPA should 

set or revise a standard under section 111. We also find 

commenter’s argument regarding 111(f) equally unpersuasive. 

Section 111(f) sets forth factors for prioritizing source 

categories for issuing NSPS; it does not address the content of 

standards to be set under section 111. 

Neither has the EPA prescribed criteria for determining 

when the revision is “appropriate” under section 111(b), as the 

commenter contends. The EPA has not stated in the NSPS reviews 

referenced in the comment or elsewhere that the EPA would only 

consider these two factors in determining whether revision is 
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“appropriate” under section 111(b) or that the EPA will regulate 

every pollutant that meets these criteria. 

In any event, with respect to methane emitted from the oil 

and gas sector, the EPA has not completed its review process. 

The EPA is continuing to assess methane emissions and evaluate 

appropriate actions for addressing these concerns. The EPA notes 

that control measures for methane are the same as those for VOC, 

which the EPA has previously regulated and is requiring further 

reduction in this NSPS review. Although the VOC requirements in 

this rule would also achieve substantial reduction in methane 

emissions, the EPA currently does not have sufficient 

information at this time to assess the extent of methane 

emissions that would remain even with the expanded VOC controls 

and whether additional measures are available and appropriate 

for addressing such emissions. For the reasons stated above, the 

EPA is continuing its assessment of methane emissions, including 

gathering and reviewing additional information, to evaluate 

appropriate actions.

3. Expanded scope of the source category

Comment: One commenter states that in the preamble, the EPA 

makes reference to its proposal to significantly expand the 

scope of oil and gas operations that would be covered by the new 

NSPS, and states that "[t]o the extent that there are oil and 

gas operations not covered by the currently listed Oil and 
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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." 76 Fed. Reg. 52745, Aug. 23, 2011. 

The commenter is not aware of any authority pursuant to which 

the EPA may affect a significant expansion of the category list 

merely through the language of the preamble in an NSPS 

rulemaking. The commenter states that in a related context, the 

CAA requires that the EPA engage in consultation with State 

governors and air pollution control agencies, suggesting that 

more than a preamble reference is needed in order to expand the 

category list and thus to impose NSPS requirements on entire 

categories of sources that had not previously been subjected to 

such requirements. See 42 U.S.C. §7411(f)(3).

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

EPA believes that the currently listed oil and natural gas 

category covers all operations in this industry. 76 FR at 52745. 

The EPA has described this listed source category very broadly, 

to “encompass the operations of exploring for crude oil and 

natural gas products, drilling for these products, removing them 

from beneath the earth’s surface, and processing these products 

from oil and gas fields for distribution to petroleum refineries 

and gas pipelines.” 49 FR at 2637. The EPA promulgated the 

existing NSPS (subparts KKK and LLL) “based on the 

Administrator’s decision that the crude oil and natural gas 
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production industry causes or contributes significantly to air 

pollution that may reasonably be anticipated to endanger public 

health or welfare” (Emphasis added). 49 FR 2636. For the reasons 

stated above, we believe that the currently listed oil and 

natural gas category covers all operations for which we are 

setting standards. That the original NSPS’s only set standards 

for a limited set of sources within the category cannot be taken 

to imply that other units were not within the scope of this 

original listing. See, e.g., Nat’l Lime Ass’n v. EPA, 627 F.2d 

at 426 n. 27 (noting that the EPA set standards for only certain 

kiln types within the source category).

Even if the original listing was not this broad, section 

111(b)(1)(A) provides the EPA authority to revise the list of 

categories, which we explained in the proposal we believe 

reasonably includes the ability to modify the scope of existing 

source categories. Section 111(b)(1)(A) does not set forth 

criteria for the EPA’s revision to the list, thus giving the EPA 

broad discretion. The information that the EPA has reviewed 

during this rulemaking continues to support the finding that 

this industry causes or contributes to air pollution which may 

reasonably be anticipated to endanger public health or welfare.

Therefore, to the extent that the original listing of the oil 

and gas source category had not covered all operations in this 

industry, the EPA is revising the listed category to include 
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those operations. While the commenter suggests that the EPA 

cannot amend a source category in a preamble, the commenter 

points to no directly applicable provision demonstrating why the 

EPA cannot do so, and does not explain why the EPA’s 

interpretation is inconsistent with the plain language of the 

CAA.

Rather, the commenter claims that 111(f)(3)suggests that 

amending a 111(b) listing cannot, or should not, be done in a 

preamble. By its terms, 111(f)(3)does not apply here. Section 

111(f)(3) requires the EPA to consult with State Governors (1) 

before promulgating standards for a listed source category for 

which the EPA had not proposed regulations before November 15, 

1990 or (2) before listing a category under section 111(f). 

Because the EPA listed this source category in 1979 and 

promulgated regulations in 1984, this rulemaking is not scenario 

(1) described above. Further, that Congress explicitly requires 

consultation in certain circumstances but not with respect to 

the EPA's authority to amend listing under 111(b) supports, 

rather than undermines, our conclusion that consultation is not 

a procedural perquisite to a 111(b) revision.

B. Major comments concerning well completions

1. Applicability and exemptions

a. Well exemptions
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Comment: One commenter suggests adding “appraisal wells” as a 

third category of well to be exempt from the REC requirements, 

and defines these wells as those drilled in an area where the 

reservoir has not been classified for that area as containing 

proved reserves of natural gas. According to the commenter, 

adding this definition and exemption better reflects the 

universe of wells for which a gas gathering line system will not 

be available. The commenter adds that it also avoids a potential 

problem where a shale play appraisal well system is effectively 

compelled to install a gathering line system before the wells 

are determined to be economically viable, in order to assure 

compliance with NSPS subpart OOOO. 

Response: The EPA recognizes that a gathering line at the well 

pad is a necessary precondition to capture flowback gas for 

emissions control so that the REC process has an outlet for the 

captured gas. However, the EPA does not agree that appraisal 

wells need to be exempt. Appraisal wells are drilled and then 

logged to assess productivity. If well logs indicate that the 

well is productive, then the cost to fracture, complete and 

produce the well is incurred. If the well logs indicate the well 

is not economically productive, then no fracturing occurs. The 

EPA therefore believes it is reasonable to require appraisal 

wells that are hydraulically fractured to comply with 

Subcategory 3 rule requirements.
Page 101 of 497

b. Threshold for low pressure (low volume) wells and wells with 

low or no VOC emissions

Comment: One commenter expresses support for the REC 

requirements and urges the EPA to limit the number of well 

completions exempted from the requirements as much as possible. 

Several commenters contend that not all well completions can be 

conducted successfully under a requirement to flow back to the 

gathering line, since the imposition of the gathering line 

backpressure may reduce the flowback gas velocity sufficiently 

so that it is not energetic enough to clean up the well of 

liquid and sand. One commenter recommends that any well whose 

reservoir pressure (measured at the wellhead immediately after 

perforation) is less than four times (in absolute units) the 

line pressure measured at the flow meter would be exempt from 

any requirement to flow to sales during the flowback period. 

According to the commenter, variability in reservoir and line 

pressures across the United States makes setting a specific 

pressure threshold difficult.

Response: The EPA has established three subcategories of wells 

in response to comments, as described above. One of those 

categories is comprised of non-wildcat and non-delineation low 

pressure wells. Low pressure wells are defined as wells for 

which the gathering line pressure at the sales meter (in psia)is 

greater than 0.443 times static reservoir pressure (in psia) 
Page 102 of 497

minus 0.092 times the vertical well depth (in feet) plus 497

psia. Thus, wells above this pressure differential must 

implement REC, while wells below this pressure differential are 

required to route emissions to a completion combustion device. 

The EPA solicited comment in the proposed rule on 

situations where REC may be infeasible and criteria and 

thresholds for distinguishing well completion operations in 

those situations from others where REC is feasible. As noted 

above, several commenters highlighted the technical issues that 

prevent an operator from implementing an REC on a low pressure 

well, which is the inability to attain a gas velocity sufficient 

to clean up the well when flowing against the gathering line

backpressure. Based on this information, the EPA agrees that a 

pressure differential threshold is reasonable and addresses the 

technical limitations of low pressure wells to produce to the 

gathering line during completion. 

As noted above, a commenter recommended specific approaches 

to developing a pressure threshold including specifying that any 

well whose reservoir pressure is less than four times (in 

absolute units) the line pressure measured at the flow meter 

would be exempt from any requirement to flow to the sales line

during the flowback period. This recommendation is based on a 

flowing bottom hole to reservoir pressure ratio of 1:2 and a 

line pressure to flowing bottom hole pressure of 1:2. The EPA 
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concurs with the commenter that flowing bottom hole pressure can 

be represented as half of the reservoir pressure for this rule. 

The EPA disagrees with the commenter that line pressure can be 

represented as half of the flowing bottom hole pressure for this 

rule since this pressure relationship can be more accurately 

determined using the Turner equation for liquids unloading from 

a well paired with models relating fluid velocity to pressure 

drop. Therefore, the EPA has modeled a worst-case pressure drop 

factor between the line pressure and flowing bottom hole 

pressure and has established a pressure threshold using this 

factor and the 1:2 factor for flowing bottom hole pressure to 

reservoir pressure. The result of this modeling is the equation 

discussed above in the definition of low pressure wells.

The EPA reviewed potential control options for wells that 

fall below the pressure threshold and determined that flaring is 

technically feasible and cost-effective. Therefore, wells with a 

pressure drop at or above this differential are required to use 

REC. Wells with a pressure drop below this differential are 

considered low pressure wells in which combustion of the 

flowback gas is required.

Comment: Several commenters address parameters for defining 

which well completions would be subject to REC requirements. 

Commenters request that the EPA exempt wells with low VOC 

concentrations from the REC requirements and not issue the 
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proposed standards before reconsidering the emissions estimates. 

One commenter suggests that the EPA exempt hydraulically 

fractured natural gas horizontal wells with de minimis VOC 

concentrations because the cost per ton of VOC reductions is 

extremely high for these wells and the emissions from the 

combustion of the produced gas could worsen ozone formation in 

the area. Commenters also state as examples some wells with low 

or no VOC as support for exempting wells with a low VOC content 

or for exempting certain classes of wells such as coal bed 

methane. Several commenters contend that coal bed methane wells 

have low VOC, while several other commenters contend that coal 

bed methane wells have no VOC. Some commenters provide examples 

of coal bed methane wells with low VOC or no VOC, and one 

commenter provides an example of a shale gas well with no VOC.

Response: The EPA acknowledges that the VOC concentration in 

natural gas can vary across wells and reservoir types such coal 

bed methane (CBM), shale, and tight sands. In response to 

comments, the EPA assessed the VOC content of coal bed methane 

(CBM) wells. However, best available data show that VOC 

concentrations among CBM wells will vary and are not always low. 

With respect to the suggestion that the EPA develop a specific 

threshold for VOC concentrations and exempt wells below such 

threshold, the EPA determined that the information provided by 

commenters is not sufficient to warrant a change in the EPA’s 
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VOC emissions estimates or to develop a VOC threshold. In any 

event, even if such a threshold can be determined, to ensure 

compliance with the rule an operator would have to determine 

with certainly before production whether a particular well was 

going to be above or below the threshold in order to mobilize 

the necessary capture equipment and secure a sales line, etc. 

This would require the operator to determine the reservoir 

composition, e.g., the gas composition prior to separation, in 

advance of the well completion. In addition, the operator would 

need to certify that the reservoir sample is going to stay 

consistent and representative of the gas stream throughout the

full completion process through multiple gas composition 

analyses. 

Taking into account the variability in VOC concentrations 

across reservoir types, the EPA’s cost analysis illustrates that 

on average, these requirements are cost-effective especially 

when taking into account the gas savings. Compliance with a VOC 

concentration threshold based rule for well completions could 

actually increase the burden to the operator by requiring 

numerous compositional analyses to demonstrate compliance with 

the rule. 

However, in response to comments, we have modified the 

provisions in the final rule that require REC for all 

hydraulically fractured gas well completions. As discussed 
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abouve, we have created three subcategories of hydraulically 

fractured gas wells: (1) wildcat (exploratory) and delineation 

wells, (2) non-wildcat and non-delineation low pressure wells 

(see further discussion below), and (3) all other wells. For 

each well completion operation at category (3) non-wildcat and 

non-delineation wells with hydraulic fracturing begun on or 

after [INSERT DATE TWO YEARS AFTER DATE OF PUBLICATION IN THE 

FEDERAL REGISTER], the standards require a reduced emission 

completion (REC) in combination with the use of a completion 

combustion device to control gas not suitable for entering the 

gathering line. For well completion operations at nonexploratory and non-delineation wells with hydraulic fracturing 

begun prior to [INSERT DATE TWO YEARS AFTER DATE OF PUBLICATION 

IN THE FEDERAL REGISTER], the final rule requires the control of 

emissions using REC or a completion combustion device. 

For category (1) wells (exploratory and delineation wells) 

and category (2) wells (low pressure wells), the final rule 

contains an operational standard that requires the use of a 

completion combustion device. However, the final rule does not 

prohibit the use of REC for completion of these wells.

2. Rule should not prescribe equipment

Comment: Several commenters suggest revising 60.5375(a)(2) 

equipment requirements to be less prescriptive, especially in 

cases where use of specified or all listed equipment may not be 
Page 107 of 497

necessary and to provide flexibility to include newly developing 

technology. Other commenters assert that language in sections 

60.5375(a)(1) and (2) stating that source owners or operators 

should “minimize the emissions associated with venting of 

hydrocarbon fluids and gas” and that “[a]ll salable gas must be 

routed to the gas gathering line as soon as practicable” is 

vague and recommended a requirement that facility owners follow 

a Best Management Practice (BMP) plan that the EPA could develop 

informed by the Natural Gas STAR program.

Response: The EPA agrees that prescribing specific equipment to 

accomplish a reduced emissions completion is not necessary and 

has revised the rule language to not prescribe specific 

equipment. The EPA has further clarified Section 60.5375(a)(2) 

to include the possibility of routing recovered gas and 

utilizing it as a fuel source. A commenter has suggested that 

the rule require a best management practice plan to determine 

when to implement reduced emission completions across a 

development area. Because completion emissions occur at the well 

rather than at the area level, the EPA does not believe that use 

of a BMP is appropriate.

3. Availability of equipment and trained personnel

Comment: Commenters state that the supply of REC equipment and 

personnel is insufficient to meet the requirements of the 

proposed rule, applied nationally. According to commenters, 
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proper surface equipment, collection infrastructure, and 

qualified personnel are not readily available; they assert that 

this equipment is fairly specialized, the shops licensed to make 

it are limited, and some of the components require a long lead 

time. For these reasons, commenters indicate that compliance by 

the issuance date of the rule would be unrealistic and that the 

EPA should provide a longer compliance period.

Response: Based on information submitted by commenters, we have 

reason to believe that currently there is significant demand for 

REC equipment. For example, Colorado, Wyoming, and the City of 

Fort Worth, Texas, require RECs under certain conditions. 

Additionally, public comments, reports to the EPA’s Natural Gas 

STAR Program, and press statements from companies indicate that 

some producers implement RECs voluntarily based upon economic 

and environmental objectives. The NSPS will undoubtedly add 

additional demands on REC equipment supply and experienced 

personnel.

If the near-term supply of REC equipment and trained 

personnel is insufficient to meet the new national demand for 

equipment and labor, immediate compliance with the REC 

requirements could be impossible, potentially causing producers 

to delay well completions until appropriate equipment and labor 

are available. Any resulting delays in well completions while 

awaiting equipment availability could cause a decrease in the 
Page 109 of 497

nationwide natural gas supply. It is not the EPA’s intent to set 

in motion a series of events through this rule that has the 

potential to affect the natural gas supply. The EPA therefore 

believes that it is important to consider the availability of 

REC equipment and personnel is its BSER analysis.

Unfortunately, the EPA is not aware of any quantitative 

information on the current and future supply of workers trained 

in REC techniques. Few data are available to quantitatively 

evaluate the current and future supply of REC equipment. 

Meanwhile, according to one commenter, about 300 REC units are 

in use today, with the ability to process about 4,000 wells per 

year, and 1,300 additional units would be required to perform 

20,000 RECs per year. About 1,600 units performing 20,000 

RECs/year implies about 12.5 RECs/year/unit, or roughly each 

unit performing one REC per month on average. The 12.5 

RECs/year/unit is reasonably consistent with the commenter’s 

cost analysis, which assumes individual REC units are leased for 

one-month periods and perform a single REC within that period. 

The NSPS proposal estimated 9,300 RECs performed for new 

natural gas well completions and 12,200 RECs performed for 

existing natural gas well recompletions. As discussed more 

below, the EPA has reevaluated the assumption that on average 

each fractured gas well is re-fractured every 10 years, which 

equates to approximately 10% of fractured gas wells being re-
Page 110 of 497

fractured each year. In the analysis supporting the final rule, 

the EPA revised estimates show the NSPS will require 

approximately 10,500 RECs to be performed annually. 

Assuming a REC unit performs 12.5 RECs/year, about 840 

units would be required. This implies a current shortfall of 

about 540 units, based upon the numbers and assumptions provided 

by the commenter. The commenter states that industry can deliver 

about 50 units per quarter, after a one-year build up period. 

Under this assumption, it would take about 3.75 years to meet 

demand. This scenario is depicted in Scenario A in the Table 2, 

assuming compliance is initiated at the beginning of the second 

quarter 2012, and the industry begins delivering 50 units per 

quarter roughly one year after the compliance date.

Surveys conducted by one commenter indicate that nine 

companies expect to perform more RECs than the current stock is 

capable of. Given current demand, it might be reasonable to 

assume industry can deliver units during the first year of 

implementation, which would reduce the time required to meet 

full demand another year to a total about 2.75 years (Scenario 

B).

An additional option to building new REC equipment to meet 

demand is to increase the productivity of equipment in use. The 

EPA estimated that flow back periods will typically be 3-10 days 

with 7 being a reasonable average. If the utilization rate of 
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REC units is increased gradually from performing 12.5 

RECs/year/unit to 14-18 RECs/year/unit, the time required to 

build the supply of REC units decreases (Scenarios C-F). As the 

Table 2 shows, each 1 REC/year/unit increase reduces the buildup 

time by about 1 quarter. As is shown in Scenario D, increasing 

the utilization rate of REC from 12.5 to 15 RECs/unit/year with 

industry supplying new units beginning with the compliance date 

would provide about two years for full build out of the REC unit 

supply.

Table 2. REC unit supply analysis

Scenario A B C D E

RECs Required 10,532 10,532 10,532 10,532 10,532

Productivity 

(RECs/year/unit) 12.5 12.5 14.0 15.0 16.0

Units Needed 843 843 752 702 658

Stock in Existence (industry can build 50 units/quarter; 

assuming industry starts with 300 units); compliance begins 

approximately at the end of the second quarter, 2012.

Scenario A B C D E

2012 (Q1) 300 300 300 300 300

2012 (Q2) 300 300 300 300 300

2012 (Q3) 300 350 350 350 350

2012 (Q4) 300 400 400 400 400

2013 (Q1) 300 450 450 450 450

2013 (Q2) 300 500 500 500 500

2013 (Q3) 350 550 550 550 550

2013 (Q4) 400 600 600 600 600

2014 (Q1) 450 650 650 650 650

2014 (Q2) 500 700 700 700 700

2014 (Q3) 550 750 750

2014 (Q4) 600 800 800

2015 (Q1) 650 850

2015 (Q2) 700

2015 (Q3) 750
Page 112 of 497

2015 (Q4) 800

2016 (Q1) 850

2016 (Q2)

Because of uncertainties in the supply of equipment and 

labor over the near-term, and based on our analysis described 

above, the EPA concludes that RECs may not always be available 

during the first two years after the NSPS becomes effective. 

Therefore, during the first two years, the BSER for well 

completions is to combust completion emissions. However, the EPA 

will allow REC as an alternative to combustion so that 

facilities that are able to obtain REC equipment may still 

capture completion emissions using a REC. At the beginning of 

the third year of implementation, capturing completion emissions 

using a REC will be considered BSER. This two-year period will 

permit the companies producing REC units to increase production 

to levels sufficient to meet new demand. In addition, because 

the new rule will require more RECs to be performed, the EPA 

believes that producers will take advantage of scale economies 

and use REC units at a higher rate of productivity than the rate 

implied by comments received.

The EPA believes that the NSPS, as finalized, will minimize 

the risks of producers slowing well completion-related 

activities in order to obtain appropriate equipment and labor, 

while not losing VOC emissions reductions because completion 
Page 113 of 497

emissions will be either combusted or captured. This would also 

minimize the possibility that the price of REC equipment and 

labor increases over the near-term, enabling producers to better 

plan efficient use of existing and new capital and labor, and 

providing additional time for innovation in reduced emission 

completion technologies.

4. Cost and emissions calculations

Comment: Some commenters request the EPA to fully explain or 

reconsider the 10 percent rate of refracturing of wells.

Response: The EPA has reevaluated the assumption that on average 

each fractured gas well is re-fractured every 10 years, which 

equates to approximately 10 percent of fractured gas wells being 

re-fractured each year based on drilling and re-fracture records 

from an industry representative. 

The EPA has received data on the percent of gas wells to be 

re-fractured per year, referred to as recompletions. This new 

information showed that the recompletion frequency can be as low 

as 0.01 percent and as high as 0.8 percent. The EPA evaluated 

this new information against the assumptions in the proposed 

rule analysis, determined that this information represents best 

available data and concluded that the impacts analysis needed 

updating to more accurately reflect the number of wells 

recompleted in a given year. Based on this information, the EPA 

has estimated the recompletion frequency to be 1 percent of 
Page 114 of 497

fractured gas wells per year. The EPA rounded the figures 

provided by the companies to reflect the uncertainty in the 

data.

5. Definition of affected facility

Comment: Several commenters assert that a well completion is 

different from a well workover and should be better defined in 

the rule. 

Response: Based on the comments received, the EPA acknowledges 

that the term “workover” is a general term that may have a 

number of different meanings. Based on the various definitions 

of the term provided by the commenters, we realize that workover 

may be interpreted to include activities that we did not intend 

to cover under the rule. Therefore, in the final rule we have

revised the definition of “well completion operation” to exclude 

the term “workover” and instead include the phrase “with 

hydraulic fracturing.”

C. Major comments concerning pneumatic controllers

1. Definition of affected facility

Comment: Some commenters request that the EPA consider excluding 

or exempting emergency and/or safety system devices (such as a 

pilot operated pressure relief valve). According to one 

commenter, safety system devices typically do not emit gas 

unless there is an emergency, have a near-zero VOC-level static 

state, and if regulated, could be replaced by substandard, 
Page 115 of 497

cheaper technology of spring operated valves which would create 

much more leakage of gas into the environment. 

With regard to emergency situations, another commenter 

argues that the proposed standards that apply to pneumatic 

controller affected facilities (§60.5390(b)) could inhibit safe 

plant operation during an emergency because they require that 

each pneumatic controller located at a natural gas processing 

plant have zero natural gas emissions. According to the 

commenter, a gas-powered controller is a reliable alternative 

for safe plant operation during emergencies, and the commenter 

suggests that the final rule include an exception to allow gas 

plants to use natural gas-driven pneumatic controllers for 

emergency plant shut down and subsequent startup. 

With regard to high-bleed pneumatic controllers, several 

commenters request that the EPA further explain when the use of 

high-bleed pneumatic controllers is allowed and provide specific

examples of exemptions. The commenters suggest exemptions that 

address situations such as those where the natural gas includes 

impurities that could increase the likelihood of fouling a lowbleed pneumatic controller, such as paraffin or salts; where 

weather conditions could degrade pneumatic controller 

performance; during emergency conditions; where flow is not 

sufficient for low-bleed pneumatic controllers; and where 

electricity is not available; and where engineering judgment 
Page 116 of 497

recommends their use to maintain safety, reliability, or 

efficiency. Several commenters request that the EPA provide 

additional information about how to demonstrate that the use of 

high-bleed pneumatic controllers is predicated as stated in 

proposed §60.5390(a). The commenters suggest that this exemption 

is very vague, will allow for excessive emissions, and is not 

enforceable. 

Response: The EPA notes that the pneumatic controller standards 

do not apply if you demonstrate, to the Administrator’s 

satisfaction, that the use of a high bleed controller is 

necessary based on operational requirements of the controller. 

As examples, the demonstration may include, but is not limited 

to, response time, safety, and actuation of valves. These 

functional exemptions to the requirement address the commenters’ 

concerns of safety, emergency, and otherwise non-routine 

situations.

Comment: Several commenters express concerns with the proposed 

rule’s treatment of various types of pneumatic devices and 

controllers. One commenter requests that the EPA clarify in 

subpart OOOO that intermittent bleed pneumatic devices are not 

affected sources. Another commenter asserts that continuous lowbleed controllers that replace existing continuous low-bleed 

controllers should not be “affected facilities.” According to 

this commenter, some designed high bleed devices may be isolated 
Page 117 of 497

from the gas pressure with a valve and operated manually on an 

intermittent basis. The commenter wants clarification in the 

rule that will allow an operator to use a high-bleed device if 

it is operated in a manner that keeps its emission levels less 

than 6 scfh. 

One commenter requests that the EPA clarify in the final 

rule that the distribution sector and self-contained devices 

that release gas to a downstream pipeline instead of to the 

atmosphere are exempt. Another commenter argues that no-bleed 

pneumatic devices have zero emissions and thus should not be 

included in the proposed rule.

One commenter discusses the use of solar-powered 

controllers, fuel-cell powered controllers, and mechanicallycontrolled devices in remote locations as an alternative to 

natural gas where grid electricity is not available. This 

commenter also recommends that the EPA set a zero emissions 

standard based upon no-bleed devices wherever electricity 

(either from a grid or from field power sources) is available 

within a reasonable distance from the facility and suggests that 

the EPA could establish an exemption to no-bleed devices where 

low-bleed devices are necessary because no-bleed devices cannot 

be feasibly installed.

Another commenter states the definition of “pneumatic 

controller” is unclear and should be revised.
Page 118 of 497

Response: The EPA is changing the affected facility definition

to continuous bleed natural gas driven pneumatic controllers to 

clarify several issues raised by commenters, including the 

applicability of intermittent bleed devices, applicability of 

pneumatic devices not related to control, applicability of 

instrument air, and applicability of no-bleed controllers. The 

emission limits in the final rule would effectively eliminate 

the use of high-bleed pneumatic controllers for new (including 

replacement) and modified continuous bleed pneumatic 

controllers. Also, to ease the burden on future replacement of 

or modification to continuous bleed controllers in natural gas 

service that bleed below the applicable emissions limit, the 

final rule requires only that these controllers be tagged as 

such, so that they can be tracked separately from devices above 

the emission limit, which have requirements to ensure 

compliance. As stated in the proposed rule’s Technical Support 

Document, it is assumed that a no-bleed controller meets the 

definition of a low-bleed controller for purposes of the 

emissions limit. The EPA also confirms that the rule 

requirements for pneumatic controllers list the industry sectors 

covered by the regulation (see §60.5430), which addresses a 

commenter’s request for clarification about distribution sector 

devices.
Page 119 of 497

Regarding the comments related to solar-powered 

controllers, fuel-cell powered controllers, mechanicallycontrolled devices and no-bleed devices wherever electricity is 

available, we considered these types of devices in the BSER 

analysis as discussed in the TSD. Any such controller system 

would require a backup system (consisting of at least an 

electrical generator) to operate the controllers when the 

primary system was inoperable. When considering the cost of the 

backup system, these options were not cost effective. 

Comment: Several commenters request an exemption for all 

affected facilities handling gas with less than 10 percent VOC 

content by weight. Some commenters offer suggestions for such 

exemption, such as requiring recordkeeping of the gas VOC 

content in order for a facility to maintain the exemption.

One commenter believes that the EPA should delete the 

pneumatic controller requirements because most of the gas 

emitted is methane, and there is little VOC emission reduction 

benefit. Another commenter suggests limiting applicability to 

pneumatic controllers at natural gas processing plants or 

upstream of processing that exceed a defined VOC threshold. 

Several commenters opine that pneumatic device definitions 

and applicability should be based on VOC emissions, not natural 

gas as a surrogate. Commenters assert that the 6 scfh highbleed/low-bleed threshold value is unsupported, that natural gas 
Page 120 of 497

VOC content varies widely, and that in most cases, 

unconventionally produced coal bed methane and shale gas have 

little if any measurable VOC. 

Several commenters also wanted to exclude pneumatic 

controllers driven by a specified percentage of VOCs. According 

to the commenters, regulating the use of compressed air or 

“instrument air” or other gas having little or no VOCs would 

impose a significant burden on the industry without any added 

benefit. 

Response: The EPA is using natural gas bleed rate as a surrogate 

for VOC emissions rate. Measuring the VOC content of a pneumatic 

controller’s bleed gas adds cost burden to companies, and to the 

EPA’s knowledge, vendors/manufacturers do not report the VOC 

emissions from a pneumatic controller primarily because the VOC 

emissions would depend on the gas composition at the site the 

pneumatic controller is located. In the Technical Support 

Document the EPA has provided cost effectiveness calculations 

for setting the pneumatic device emission limits.

2. Controllers in the transmission and storage segment

Comment: Several commenters requested the EPA reevaluate 

requirements for pneumatic controller/devices in the natural gas 

transmission segment of the industry. The commenters argue that 

the proposed rule’s applicability is too broad and would result 

in an undue recordkeeping and permitting burden. 
Page 121 of 497

Several commenters recommend that subpart OOOO should limit 

pneumatic controller applicability to upstream processes. Some 

commenters suggest that, for natural gas transmission and 

storage, either pneumatic controllers should be completely 

excluded or subpart OOOO should limit applicability to equipment 

located at “conventional” facilities, e.g. within the fence line 

at a compressor stations. One commenter recommends limiting the 

emission limit requirement to controllers at natural gas 

processing plants or locations upstream from gas processing that 

exceed a defined VOC threshold. The commenter suggests that this 

exclusion would reduce administrative costs in two ways: 

mandatory recordkeeping and reporting would be removed and the 

documentation required to explain why excluded controllers would 

no longer be necessary would be removed. Another commenter 

suggests that the EPA state in the final rule that NSPS/NESHAP 

applicability alone should not trigger minor source permitting 

requirements.

Response: The EPA is revising the requirements for pneumatic 

controllers to apply to production through processing, and the 

EPA will collect data under Subpart W of the greenhouse gas 

reporting rule to inform a decision on potential future action.

No VOC threshold will be included in this regulation given the 

arbitrary nature of defining one using available data.

3. Cost and emissions calculations
Page 122 of 497

Comment: One commenter asserts that the EPA’s estimate of 14,000 

new and replaced controllers in a given year is grossly 

underestimated. By the commenter’s data and calculations, 

approximately 750,000 controllers in Texas alone may need to be 

replaced (unless an exemption is granted) once a well becomes 

subject to the new rule. 

Response: The commenter incorrectly claims that the EPA’s 

estimate of the number of pneumatic controllers installed in a 

given year is 14,000. In Section 5.3.2 of the Technical Support 

Document, the EPA explains its methodology for estimating the 

number of pneumatic controllers in both gas/oil production and 

gas transmission and storage. Table 5-3 gives a breakdown of 

snap-acting versus bleed controllers and shows the total number 

of controllers to be 33,673. The commenter did not provide data 

to support its claim of 750,000 pneumatic controllers in Texas, 

and consider that not all would need to be replaced. A bleed 

rate threshold of 6 scfh is established in the rule for the 

production sector.

D. Major comments concerning compressors

1. Dry seals versus wet seals

Comment: Several commenters address the issue of whether the EPA 

should permit the use of a system other than dry seal to control 

emissions from centrifugal compressors. Some commenters provide 

information on situations where dry seal systems for centrifugal 
Page 123 of 497

compressors are not technically feasible, such as where gas 

composition is inadequate, in some processing plants that 

already have a capture system in place, and in retrofits of some 

existing compressors due to housing design or operational 

requirements. Commenters opine that the rule should allow 

compliance using either system, depending upon particular 

circumstances, and should not preclude use of a wet sealequipped compressor with controls capable of meeting a 95 

percent VOC control efficiency or routing captured seal-oil gas 

to a fuel gas, recycling, or other processing system. According 

to another commenter, it would not be feasible to capture gas 

that escapes from a centrifugal compressor and route it back to 

a low-pressure fuel stream for combustion as fuel gas; although 

such a process would capture a minimal amount of VOC emissions, 

the high cost of equipment to recapture the emissions would make 

the method described cost-prohibitive.

Commenters generally concurred that a 95 percent reduction 

in emissions was achievable through installing a capture system 

on a wet seal compressor. In addition, commenters disagreed with 

the EPA’s cost estimates and concluded that a wet seal capture 

system is cost-effective. 

Response: In the preamble to the proposed rule, the EPA 

solicited comments on situations where the use of a dry seal is 

infeasible or otherwise inappropriate and wet seal is the only 
Page 124 of 497

option. 76 FR 52762. As noted above, several commenters provided 

information on situations where dry seals are not technically 

feasible. Therefore, the EPA has concluded that dry seal is not 

the BSER for all new and modified centrifugal compressors. 

Instead, the EPA separately evaluates the control options for 

wet seal compressors. The EPA has identified one control option 

through its review of available information, including comments 

and other information obtained since proposal. The option is to

route captured seal-oil gas to the compressor suction, fuel gas 

system, or flare, all of which can achieve 95 percent control 

efficiency.

Based on the discrepancy between commenters’ and the EPA’s 

cost data, the EPA re-evaluated its cost information for this 

control option. The EPA cost estimates in the proposed rule 

assumed the use of a new flare to combust the captured seal oil 

gas, and based on commenter information, the EPA is revising 

this assumption since a new flare or other combustion source is 

expected to be available in gas processing facilities. From 

reviewing comments received, the EPA is aware that the captured 

gas is not always routed to a flare but in many cases is routed 

back to the compressor suction or fuel system. Given this 

information, the EPA has re-evaluated the costs for the 

centrifugal compressor wet seal capture system and determined a 

system of this type, in which the seal oil degassing vents are 
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routed to fuel gas, compressor suction, or an existing flare, 

would cost $22,000. The estimated cost includes an intermediate 

pressure degassing drum, new piping, gas demister/filter, and a 

pressure regulator for the fuel line. With this cost, the 

estimated VOC control cost-effectiveness is $161/ton of VOC for 

the processing sector. If savings are included, the costeffectiveness for VOC control is -$2,134/ton of VOC.

In light of the above, we have determined that the control 

option described above is the BSER for wet seal compressors. 

Accordingly, the final NSPS would require that wet seal 

compressors reduce emission by 95 percent. For dry seal 

compressors, the only emission control option we have identified 

is the use of dry seal. Accordingly there is no requirement in 

the final rule for dry seal compressors, and dry seal 

compressors are not affected facilities under the NSPS.

2. New source definition

Comment: Several commenters oppose the proposal in section 

60.5365(b) and (c) that a reciprocating compressor be considered 

as “commenced construction” on the date of installation at a 

facility. Commenters argue that the EPA was “arbitrary and 

capricious” in proposing to apply the concept of “commenced 

construction” in the NSPS context to a relocated compressor, 

because the Agency had no “reasoned explanation” for making the 

change and that applying the concept of “commenced construction” 
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to a relocated compressor is contrary to the plain language of 

the CAA. 

Response: As provided in the NSPS General Provisions at 40 CFR 

60.14(e)(6), relocation of an existing affected facility is not 

modification. Based on information received from commenters, the 

EPA acknowledges that each compressor’s manufacture date can be 

tracked, and the EPA is revising the rule defining new source 

reciprocating compressors based on the equipment manufacture 

date.

E. Major comments concerning storage vessels

1. Applicability threshold metric

Comment: Numerous commenters objected to the EPA’s proposed use 

of liquid throughput to determine which storage vessels should 

be subject to the standards, asserting that the high variability 

in volatility of stored liquids and other parameters affecting 

emissions makes throughput a poor indicator of VOC emissions.

The commenters indicate that, as a result, basing applicability 

on throughput would bring many storage vessels with low VOC 

emissions (some less than 1 tpy) under the standard and the 

required emission controls would not be cost effective. Some 

commenters point out that certain storage vessels with high 

emissions might not be subject to the standards based on 

throughput.
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Response: The EPA agrees with the commenters that applicability 

should be based on VOC emissions instead of liquid throughput

and that the use of a VOC emissions threshold is more flexible 

approach, ensuring that controls will be required only on those 

storage vessels where they can be applied cost-effectively. This 

approach also allows for broader coverage across all types of 

storage vessels, regardless of the fluid that is stored or where 

the tank may be located. The final rule reflects this change.

Due to the large variability of emission factors from different 

shale formations, we do not think it is appropriate to use an 

average emission factor for all tanks. Instead, the final rule 

requires each facility to determine its own emission factor and 

calculate the estimated emissions from each storage vessel.

2. Definition of affected facility

Comment: Numerous commenters commented on the definition of 

storage vessel in subpart OOOO, calling for greater clarity and 

consistency, and requesting that certain activities or equipment 

be included or excluded from the definition.

Response: The EPA agrees with the commenters who assert that a 

more specific and consistent definition of a storage vessel is 

needed. In the final rule, we have adopted a definition similar 

to that found in other rules, which excludes pressure vessels, 

as they are regulated in NESHAP subpart HH. However, we adopted 

several differences necessary for the oil and gas source 
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category. First, we have chosen not to exclude all tanks 

permanently attached to motor vehicles. Since there are many 

tanks in this source category that travel from site to site, we 

did not feel it was appropriate to exclude all of these tanks 

from control requirements. Instead we have set a minimum amount 

of time that the tank must be stationed at the same site before 

it is considered to be stationary and subject to subpart OOOO. 

Second, we have not excluded wastewater tanks, as there are no 

separate standards for wastewater tanks in subpart OOOO, whereas 

other rules typically exclude them because they are regulated 

under different requirements.

The final rule applies the storage vessel NSPS to each 

individual storage vessel (as opposed to a tank farm or some 

other collection of storage vessels) that emits at least 6 tpy 

of VOC, regardless of the material that the tank is storing or 

the location of the tank. Since the applicability of the NSPS, 

as finalized, is not based on throughput, we believe it is not 

necessary to specify which types of stored materials are 

regulated and which are not. If a stored material is emitting at 

least 6 tpy of VOC, then the storage vessel will need to reduce 

its VOC emissions by 95 percent.

Comment: Some commenters assert that the EPA should limit 

applicability to storage vessels that are stationary and should 
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clarify the meaning of “stationary” to include or exclude 

certain types of tanks.

Additionally, the EPA received comments requesting that the 

stationary aspect of the “storage vessel” definition should be 

consistent with other rules, while acknowledging the particular 

scenarios unique to the oil and gas production sector. The 

commenter notes that the stationary aspect of a storage vessel 

is typically addressed by the EPA in terms of whether it is 

reasonably portable, although the EPA sometimes addresses 

portability based on the size of the vessel. The commenter 

states that another criterion specified by the EPA in several 

regulations is that “vessels permanently attached to motor 

vehicles” are not storage vessels, and the EPA has issued a 

determination that this exemption extends to tanks “equipped 

with a permanently attached wheel assembly and a truck hitch” 

(U. S. Environmental Protection Agency, letter from George T. 

Czerniak to Ken Comey, Flint Hills Resources L.P., September 2, 

2004.) According to the commenter, this renders most so-called 

frac tanks, Baker tanks, ISO tanks, etc. exempt from the storage 

tank provisions when this form of definition is used. However, 

the commenter recognizes that such tanks sometimes become 

effectively “stationary” in oil and gas production operations, 

and suggests that storage vessels should be deemed stationary if 

they remain at a given site for more than 180 consecutive days, 
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consistent with the period of time allowed under §60.14(g) to 

achieve compliance after a modification. The commenter notes 

that this 180-day period is reasonable given that the definition 

of non-road engines in 40 CFR 89.2 allows a period of 12 

consecutive months. 

The commenter also points out that cost effectiveness of 

the proposed control measures has been evaluated under the 

assumption that storage vessels remain in place for the useful 

life of the control equipment, and thus the control costs are 

amortized over a period of years. Since the cost per ton of 

emission reductions would be much higher if the controls were 

applied to a tank that is only on site temporarily, the 

commenter believes that a cost-effectiveness analysis for 

permanent storage tanks would not be valid for temporary storage 

tanks, and thus the control requirements for permanent storage 

tanks are not justified for temporary storage tanks. The 

commenter provides recommended language for the definition of 

“storage vessel” that addresses this and other concerns. Another 

commenter similarly states that costly control requirements are 

not appropriate for temporary tanks (on site less than 180 

days).

Response: NSPS applies only to stationary sources. For the 

reasons stated below, the EPA has revised the definition of 
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storage vessel to clarify that a storage vessel is considered 

stationary if it remains on a given site for more than 180 days.

In general, we agree with the commenter’s discussion about 

the EPA’s past practices related to stationary storage vessels. 

In particular, we agree that the inherent differences between 

“mobile” tanks in this source category and other categories 

indicate that they should be regulated differently. However, we 

disagree that the mobility aspect of the storage vessel would 

render it not to be cost effective to control.

3. References to MACT standards

Comment: The EPA received comment asserting that the outcome of 

its BDT analysis for proposed subpart OOOO was calculated to 

achieve the same level of control as subpart HH – undermining 

the BDT determination and effectively (and unlawfully) extending 

subpart HH major source MACT requirements to area source storage 

tanks.

As a result, the commenter asserts that the EPA’s analysis 

precludes other potentially relevant regulatory alternatives –

such as marginally less effective controls that might be applied 

to a broader range of storage vessels. The commenter states that 

the EPA’s failure to consider other control techniques and other 

levels of control efficiency that might be achieved by its 

preferred techniques is arbitrary and capricious. 

Response: Contrary to these assertions, the EPA’s proposed BSER 
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determination for storage vessels was not calculated to achieve 

the same level of control as the existing MACT standard for 

major source storage vessels in 40 CFR part 63, subpart HH. The 

BSER analysis for storage vessels consists of the same steps as 

those for other affected sources evaluated in the proposed NSPS. 

Specifically, the EPA evaluated available information to 

identify VOC control options. The EPA then assessed various 

aspects of the control options, including their VOC reduction 

potentials, their cost effectiveness, and secondary air impacts. 

The commenter did not claim that any part of the EPA’s analysis 

above was inaccurate or inappropriate. Rather, the commenter 

notes that the EPA only analyzed two controls and failed to 

consider other “potentially relevant regulatory alternatives.” 

However, the commenter did not identify any other control option 

for the EPA’s consideration. The commenter simply suggests that 

the EPA should consider some less effective controls. Without 

more information, it is unclear whether a less effective control 

would in fact qualify as BSER for controlling VOC emissions from 

storage vessels considering that there are efficient and cost 

effective controls. 

Further, the determination that a 95 percent level of 

control is BSER for this emission source was determined prior to 

adopting the subpart HH requirements. The two control devices we 

analyzed are known to be commonly used for these emission 
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sources in this industry. We found both to be cost effective, 

thus establishing 95 percent control as BSER. We note also that 

the referenced section of subpart HH (section 63.766(b)) 

requires that the storage vessel be equipped 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 

combination of control devices that meets any of the conditions 

specified in §63.771(d).” Subsection 63.771(d) goes on to 

specify a wide range of control devices that the source may use 

to achieve BSER (95 percent control). Other control techniques 

that the commenter claims are “marginally less effective” would 

not be BSER precisely because they are less effective, 

regardless of the cost of those controls. We believe that the 

wide range of controls allowed under the proposed rule is 

sufficient to meet the diverse requirements of this industry.

Comment: Two commenters state that the cost of the performance 

tests, monitoring, recordkeeping, etc. that are required through 

cross-references to 40 CFR 63, subpart HH were not adequately 

considered by the EPA in the cost effectiveness determination 

for subpart OOOO, which applies to dispersed locations that do 

not have electricity or automation, and have limited remote 

transmitting unit (RTU) space. 

Response: Based on this and other comments detailed in the RTC 

for this final rulemaking, the EPA decided to remove from 
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subpart OOOO the citations to the requirements for performance 

tests, monitoring, recordkeeping, etc. in subpart HH and instead 

incorporate the appropriate subpart HH language into subpart 

OOOO. This process included an evaluation of whether the subpart 

HH requirements make sense in the context of subpart OOOO. The 

requirements that we incorporated into subpart OOOO were those 

that we believe are necessary to assure regulatory agencies and 

the public that compliance with the emission limitations is 

achieved.

4. Availability of control equipment

Comment: Some commenters believe that there will be a shortage 

of control equipment available to meet the proposed storage 

vessel requirements, and recommend revisions to the compliance 

deadline for storage vessels based on a variety of 

considerations, including the availability of control devices, 

lead time needed for installation, and the number of affected 

oil and gas wells.

Response: The EPA agrees that some lag time may be needed after 

initial start-up for the owner or operator to determine the 

long-term production level of a well and to procure the 

appropriate control equipment. For this reason, the EPA has 

decided to follow the approach taken in the Wyoming rules for 

new sources, which allows from 30 to 90 days for a source to 

achieve compliance, depending on the area of the state. Wyoming 
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allows only 30 days in ozone nonattainment areas, 60 days for 

concentrated development areas or 90 days elsewhere in the 

state.

However, for replacement storage vessels or additional 

storage vessels at well sites with one or more wells already in 

production, we believe the operator already should have 

information on liquid composition and throughput. This 

information would allow estimation of VOC emissions to determine 

applicability of control requirements and for acquisition and 

installation of a control device concurrent with the replacement 

or additional storage vessel being installed. In the final rule, 

for storage vessels at well sites with no well already in 

production, we have provided for a 30-day period for throughput 

to stabilize and for the operator to estimate VOC emissions to

determine whether a control device will be required. If VOC 

emissions are estimated to be at least 6 tpy, the operator is 

provided an additional 30 days for the control device to become 

operational. We believe that the Wyoming experience illustrates 

that this will be sufficient time to size and obtain suitable 

controls. In addition, we note that the final rule no longer 

cites to the control requirements of subpart HH as discussed 

above.

Regarding the number of storage vessels associated with 

thousands of existing oil and natural gas wells in existence, we 
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note that the final rule applies only to new, reconstructed and 

modified storage vessels emitting at least 6 tpy of VOC. In 

addition, our analysis shows that at the final applicability 

threshold of 6 tpy of VOC, the required controls are cost 

effective.

F. Major comments concerning equipment leaks

Comment: The EPA received varied opinions regarding use of the 

optical gas imaging (OGI) detection systems. Certain commenters 

state that the use of optical imaging in all areas of the 

proposed sector rule, not just gas processing facilities, would 

be beneficial in reducing emissions and simplifying the LDAR 

program, and some of these commenters support the use of 

auditory, visual, and olfactory inspections, at a minimum, to 

minimize the fugitive emissions from equipment leaks. Some 

commenters assert that Method 21 and existing systems should 

remain the primary monitoring method for LDAR programs, though 

OGI and other technical advances are useful and could supplement 

existing programs. According to these commenters, infrared 

images cannot provide quantitative measures of the amounts of 

leaking gas, infrared optical imaging cameras only detect 

extremely large leaks, and well-designed and implemented LDAR 

programs provide demonstrated emissions reductions. 

Several commenters state that implementing an OGI-only 

alternative work practice (AWP) is consistent with the 
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monitoring requirements for the mandatory GHG reporting under 40 

CFR Part 98 subpart W and using such an approach to satisfy both 

LDAR and GHG monitoring would improve its effectiveness and 

reduce duplicative and redundant requirements for facilities. 

These commenters urge the EPA to return to an OGI AWP without 

requiring an annual Method 21 survey, on the basis that 

analytical and field studies demonstrate AWP equivalency, or 

urge the EPA to evaluate the use of a one-time, side-by-side 

survey using OGI and Method 21 as part of initial compliance. 

The EPA also received requests to restore the 10 percent AWP 

Sensitivity Test Option, to clarify and modify the video 

recording requirements, to evaluate how the video data will be 

used and whether a complete video recording is really needed, 

and to work with stakeholders to develop an OGI Application 

Protocol for the AWP that is based on OGI techniques for LDAR 

programs.

Regarding cost effectiveness, some commenters suggest that 

the EPA use optical imaging as a pilot program to better 

estimate its cost effectiveness, and others suggest that the EPA 

base the cost effectiveness of LDAR on all VOC pollutants as 

well as GHG emissions, such as methane.

Response: Optical gas imaging was considered in the technology 

review, but was not determined to be BSER for any of the oil and 

gas segments. The cost effectiveness of the OGI LDAR program was 
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not calculated because the emission reductions from this program 

could not be quantified. Because this is a VOC rulemaking, GHG 

emissions cannot be used to determine the cost effectiveness of 

OGI monitoring, and therefore the option of OGI could not be 

considered as BSER for the oil and gas segments. The NSPS 

requirements do allow the use of OGI as an alternative work 

practice under section 60.18(g), which also requires an annual 

Method 21 survey of all of the components. Currently, the agency 

is working on a uniform standards rule that would allow the use 

of OGI as an alternative for the Method 21-based LDAR programs. 

We intend to provide the use of these uniform standards for 

equipment leak detection and repair when they become final.

The EPA did not receive additional data from commenters to 

support the statement that an OGI only survey is comparable to 

Method 21-based LDAR program. Therefore, we believe the AWP in 

section 60.18(g) is appropriate and do not believe that 

revisions to the requirements are necessary. We urge the 

commenter to provide their comments related to the video 

identification of components and the 10% sensitivity test option 

when the Uniform Standards are proposed.

G. Major comments concerning notification, recordkeeping and 

reporting requirements

1. 30-day notification and annual reports
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Comment: Multiple commenters state that the 30-day advance 

notification of well completions under §60.5420(a) should be 

removed from the final rule. Commenters assert that this and 

notification requirements in §60.7(a) are unduly burdensome and 

costly, not adequately explained, not related to verifying 

compliance with the proposed rule and could conflict with the 

need to protect proprietary business information. 

Multiple commenters also note that industry’s estimate of 

annual completions is several times higher than the EPA’s 

estimate of 20,000 completion and recompletion operations 

annually. The commenters believe that these requirements will 

likely overwhelm both regulated entities and state regulators 

alike. Commenters offer suggestions including requiring annual 

certifications or maintaining records available for inspection, 

reducing the proposed advance notification requirement to 5-10 

days, and considering notification programs such as those in 

Texas and Wyoming. Different commenters support or oppose 

requiring a 30-day advance notice with follow-up notification of 

1-2 days before an impending completion.

Several commenters suggest that the EPA should coordinate 

with state and local agencies to eliminate duplicative 

recordkeeping and reporting requirements, and that records of 

interest other than those submitted to the respective Oil and 
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Gas Commissions should only be required to be retained and 

available upon inspection, similar to other permit requirements.

Several commenters do not agree that an annual report under 

60.7(a)(1), 60.7(a)(3), and 60.7(a)(4) adds any value for 

verifying compliance and the EPA should remove this requirement 

from the final rule. The commenters add that the best method for 

compliance is for an owner or operator to maintain necessary 

records and to have the records available for review during an 

on-site inspection. One commenter suggests the annual report 

should include for each type of affected facility (1) the total 

number of affected facilities at the site; (2) the number of 

facilities that became affected facilities during the reporting 

period; (3) the number of exempted facilities; and (4) the 

number of affected facilities with a non-compliance situation 

during the reporting period. One commenter suggests that it 

would be easier for facilities to submit an annual report on a 

set date each year, and multiple affected facilities could be 

included in a single report. Two commenters propose that all 

notifications for each year be delivered in a single annual 

report corresponding to the reporting period in which the 

affected facilities become subject to the rule. One commenter 

suggests that operators should be required to keep records at 

the nearest manned office, but reports should only be required 

if they are requested by the EPA.
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The commenters recommend, where feasible, streamlining the 

final notification and reporting requirements to eliminate 

unduly burdensome notification and reporting requirements.

Response: The EPA agrees that certain notification, 

recordkeeping, and reporting requirements in the general 

provisions are unduly burdensome. For that reason, well 

completions, continuous bleed natural gas driven controllers, 

and storage vessels will be exempt from the notifications 

required by sections 60.7(a)(1), 60.7(a)(3), and 60.7(a)(4). The 

EPA does not believe that 30-day notification prior to a well 

completion conflicts with proprietary business information. The 

EPA does not believe that 3 days is sufficient time for 

inspectors to visit and observe a well completion. To lessen the 

burden of the 30-day notification requirement for well 

completions the EPA will instead require a single bulk 30-day 

notification, which will include future estimated dates of well 

completions plus an advance notice via email to the EPA or 

delegated authority no earlier than 3 days or late than 2 days 

prior to completion. The EPA is not limiting the 30-day bulk 

report to a written format. The rule language is flexible so 

that electronic communication notification is allowed. 

To lessen the reporting burden, the EPA is eliminating the 

requirement to list all affected facilities in the annual 

report. The EPA will revise the rule to require that only new or 
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modified affected facilities during the reporting period be 

listed in the annual report. However, the report must include a 

record of all deviations in cases where well completion 

operations with hydraulic fracturing were not performed in 

compliance with the requirements for each gas well affected 

facility.

Comment: One commenter requested that the EPA add a selfcertification requirement to the annual report similar to that 

used in the title V program. The commenter recommended that the 

final rule require the annual report to include a statement 

signed by a senior official of the facility attesting to the 

truth, accuracy and completeness of the report.

The commenter also requested that the EPA require that the 

annual reports be submitted electronically to facilitate making 

the reports publicly available. The commenter suggested using 

social media outlets, smart phone applications, and other 

electronic means to make the annual reports readily available. 

Response: The EPA agrees that self-certification is an important 

mechanism for assuring the public that the information submitted

by each facility is accurate. In addition, the title V program 

has successfully employed self-certification since its 

inception. Therefore, we are requiring self-certification, based 

on requirements in the title V program, in the final rule.
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While we agree that having annual reports readily available 

to the public is a desirable goal, we did not identify any 

reporting programs or electronic databases that may be used for 

this purpose without significant modification. Therefore, we are 

not requiring annual reports to be submitted electronically, but 

we will continue to evaluate this option in the future.

2. Duplicative recordkeeping and reporting requirements

Comment: Multiple commenters state that the notification, 

recordkeeping, monitoring, and annual reporting requirements in 

the proposed NSPS are duplicative and extremely burdensome for 

operators and for state regulators with limited resources. The 

commenters make both general and specific recommendations to 

revise the reporting requirements in the final rule to eliminate 

duplication and reduce burden or better inform the public and 

regulatory agencies about deviations. Some commenters would 

eliminate all or some reports, while others argue that reporting 

is an essential compliance and enforcement mechanism and that 

additional information should be provided. Some commenters feel 

that an owner or operator should maintain necessary records and 

have them available for review. 

Commenters want the compliance assurance requirements to be 

appropriate for the oil and gas industry and commensurate to the 

environmental benefit that will be generated. For example, some 

commenters feel that the EPA should exempt small sources 
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regulated under this rule from the notification and reporting 

requirements.

Response: We have considered these and other related comments 

presented in the RTC regarding the proposed reporting 

requirements. The EPA agrees that certain notification, 

recordkeeping, and reporting requirements are unduly burdensome

and believes it is important to minimize the burden of reporting 

requirements. The EPA also agrees that states and other 

enforcement entities are confronting limited resources and that 

visiting sites is not always practical. For that reason, the EPA 

believes notifications and reporting requirements are vital to 

ensure compliance with our regulations. Therefore, the EPA has 

evaluated all of the notification, recordkeeping, and reporting 

requirements in an effort to streamline the requirements and 

reduce burden on both industry and enforcement and has deleted 

duplicate and unnecessary reports throughout the affected 

subparts. These changes will streamline the reporting process 

and reduce the reporting burden on sources. For example, well 

completions and continuous bleed natural gas controllers are

exempt from the notifications required by sections 60.7(a)(1), 

60.7(a)(3), and 60.7(a)(4). In addition, the EPA has revised the 

rule language such that only continuous bleed natural gas 

controllers installed, modified, or replaced during the 

reporting period are reported in the annual report. In addition, 
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the EPA has revised the 30-day individual notification 

requirement for well completions, as discussed above. 

3. Electronic reporting of emissions data

Comment: Commenters suggest a variety of ways in which 

electronic reporting could be structured and implemented, with 

attention to coordination with various CAA requirements and 

programs to avoid duplicative and potentially burdensome 

requirements. Several commenters support electronic reporting of 

emissions data from all sources to be stored on existing the EPA 

databases, such as the e-GGRT or added to the TRI, and available 

to the public. These commenters believe that communities must 

have access to air quality information in order to protect 

public health. One commenter objects to the use of e-GGRT as a 

reporting mechanism in place of a state’s own tracking system, 

where the state has enforcement responsibility for the emissions 

date and tracking of sources subject to the proposed rule. The 

commenters also suggested a variety of ways in which electronic 

reporting could be structured and implemented.

Several commenters oppose the implementation of electronic 

reporting at this time and are concerned that that an ERT will 

result in numerous complications and undue additional burden. 

The commenters point out that the EPA’s experience with e-GGRT 

indicates that considerable time and resources are needed to 

develop and implement efficient systems and to ensure that 
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electronic reporting enhances efficiency rather than incurring 

additional burden on affected sources. The commenters state that 

a potential disadvantage associated with an ERT is that new 

and/or alternative test methods would not be in the system. In 

addition, the commenters believe that an ERT could be 

complicated and burdensome for smaller companies that lack 

environmental personnel or experience with electronic reporting 

under other rules. The commenters suggest that if the EPA 

delegates authority to states to implement and enforce the 

standards, some states may be unable or unwilling to accept 

electronic reports. The commenters urge the EPA to consider 

other more simplified options to report only the needed 

information.

Response: While the EPA supports and encourages electronic 

reporting, after further consideration of all the comments, we 

do not believe the e-GGRT is the appropriate mechanism for 

electronic reporting under this rule. The e-GGRT is not designed 

to accept all of the types of information required to be 

reported under the final rule, and significant modification of 

the system would be required to make it operational for this 

rule.

However, the final rule does include reporting of 

performance test data via the ERT. The EPA must have performance 

test data to conduct effective reviews of CAA sections 112 and 
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129 standards, as well as for many other purposes including 

compliance determinations, emission factor development, and 

annual emission rate determinations. In conducting these 

required reviews, the EPA has found it ineffective and time 

consuming, not only for us, but also for regulatory agencies and 

source owners and operators, 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.

In the final rule, as a step to increase the ease and 

efficiency of data submittal and improve data accessibility, the 

EPA is requiring the electronic submittal of select performance 

test data. Data entry will be through an electronic emissions 

test report structure called the Electronic Reporting Tool 

(ERT). The ERT will generate an electronic report which will be 

submitted using the Compliance and Emissions Data Reporting 

Interface (CEDRI). The submitted report is submitted through the 

EPA’s Central Data Exchange (CDX) network for storage in the 

WebFIRE database making submittal of data very straightforward 

and easy. 
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One major advantage of submitting 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 what testing 

information 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.

State, local, and tribal agencies can also benefit from a 

more streamlined and accurate review of electronic data 

submitted to them. The ERT allows for an electronic review 

process rather than a manual data assessment making review and 

evaluation of the data and calculations easier and more 

efficient. Finally, another benefit of submitting data to 

WebFIRE electronically is that these data will greatly improve 

the overall quality of the existing and new emission 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 will 
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be able to ensure that emission factors, when updated, represent 

the most current range of operational practices. 

X. Summary of Significant NESHAP Comments and Responses

For purposes of this document, the text within the comment 

summaries was provided by the commenter(s) and represents their 

opinion(s), regardless of whether the summary specifically 

indicates that the statement is from a commenter(s) (e.g., “The 

commenter states” or “The commenters assert”). The comment 

summaries do not represent the EPA’s opinion unless the response 

to the comment specifically agrees with all or a portion of the 

comment.

A. Major comments concerning applicability

1. Previously unregulated sources

Comment: One commenter supports the EPA’s regulation of 

previously unregulated sources in the Oil and Natural Gas Sector 

and the commenter asserts that sections 111, 112(c), and 112(k) 

(Urban Air Toxics Strategy) support their position regarding 

this regulation of previously unregulated sources. The commenter 

asserts that historical regulation of emission sources within 

the sector leaves a large number of dehydrators, storage vessels 

and equipment at gas processing plants unregulated. 

Additionally, the commenter states that historical 

regulation has also not limited emissions from a number of other 

emission sources (i.e., wells, pneumatic devices, compressor 
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seals, valves, or flanges or other production equipment located 

at oil and gas production facilities or natural gas storage 

transmission facilities).

One commenter supports the EPA’s recognition of the need to 

control emissions from previously uncontrolled emission points. 

However, the commenter believes that the EPA has not satisfied 

section 112(d)(2)-(3) of the Clean Air Act and that the EPA 

needs to calculate the MACT limit based on the best-performing 

sources that currently exist. Additionally, according to the 

commenter, the EPA discovered more uncontrolled emission points 

than it is planning to control. The commenter recommends that 

the EPA address all of the uncontrolled HAP emission points of 

which it is aware.

Response: As the commenter notes, historical regulation of HAP 

emissions from the oil and gas sector has not covered all 

emission sources in this sector. Congress expressly limits the 

EPA’s authority to regulate HAP emissions from this sector. For 

instance, section 112(n)(4)(A) prohibits aggregation of

emissions from any oil and gas exploration or production wells 

(with their associated equipment) in determining major source 

status or for any purpose under section 112. Section 112(k) (and 

the Urban Air Toxic Strategy) noted by the commenter is designed 

to address area source emissions in urban areas. Section 

112(n)(4)(B) limits the EPA’s authority to list and regulate 
Page 151 of 497

area sources under section 112(k) to only areas that meet 

certain population threshold and only upon making the requisite 

adverse effect finding. In light of the above, it is not clear 

whether and to what extent emissions from the sources noted in 

the comment (e.g., well completions, pneumatic controllers, or 

other production equipment) can be effectively controlled under 

section 112.

However, where appropriate, the Agency continues to take

actions to further reduce emissions from this sector. In this 

final rule, the EPA is promulgating MACT standards for major 

sources of glycol dehydrators and storage vessels that were left 

unregulated in the original NESHAP. In addition, the EPA is 

promulgating NSPS to address VOC emissions from emission sources 

noted in the comment. Control of VOC emissions from these 

sources will likely result in incidental HAP emission reductions 

as well.

B. Major comments concerning the risk review

Comment: One commenter states that the EPA’s analysis for 

subpart HH revealed two facilities (Hawkins Gas Plant, Hawkins, 

TX and Kathleen Tharp 2, Huffman, TX) with a cancer MIR greater 

than 100-in-1 million based on MACT allowable emissions. Since 

the EPA determined that these facilities had a cancer MIR 

greater than 100-in-1 million based on MACT allowable emissions, 

the EPA determined that the risks are unacceptable for the ONG 
Page 152 of 497

production MACT category and additional regulation was needed. 

However, the commenter believes these results are entirely 

incorrect due to fundamental errors in the EPA’s calculations of 

MACT allowable risk for these two facilities. In addition, even 

if the analysis had been correct, the commenter states there are 

significant issues associated with the data for both of these 

facilities, which the commenter discusses in detail, that the 

commenter believes are sufficient to invalidate the results and 

the EPA’s conclusion that risks from the ONG production source 

category are unacceptable. 

Response: We have reviewed our risk results for Oil and Natural 

Gas Production and agree with the commenter. The NEI facility 

information for Hawkins Gas Plant was not correct and the 

multiplier used for the allowable calculation was too high. 

After correcting the multiplier the MIR for this facility is 3-

in-1 million. For the Kathleen Tharp 2 facility, the actual 

emissions value was and the allowable multiplier used were too 

high, resulting in an incorrect MIR. After corrections were 

made, the MIR for this facility is below 1-in-1 million. After 

making these changes, and further reviewing our risk results, we 

determined that the highest remaining cancer risk for ONG is 14-

in-1 million for a glycol dehydrator at the Vintage Production 

facility in Ventura, CA. We find this level of risk acceptable. 

We then considered whether this revised standard (existing MACT 
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plus small dehydrator MACT) provides an ample margin of safety. 

Since this unit is a small dehydrator (this unit has a design 

throughput of 1 MMSCFD), it will be subject to the small 

dehydrator BTEX limit in the final rule. We determined the 

applicable BTEX limit for this unit under the final MACT 

provisions and determined that the resulting MIR is less than 1-

in-1 million. We conclude that this provides an ample margin of 

safety.

In addition, we are including the 0.9 Mg/yr benzene 

compliance alternative in the final amendments for subpart HH. 

See additional discussion above in section VII.A.

Comment: One commenter states that the EPA bases the decision to 

eliminate the 0.9 Mg/yr benzene emission limitation for subpart 

HHH on two basic factors: (1) it would reduce the cancer MIR 

from 90-in-1 million to 20-in-1 million, and (2) the cost 

effectiveness to comply with this option is reasonable. The 

commenter states that both of these conclusions are erroneous.

First, the commenter states that removal of 0.9 Mg/yr 

benzene alternative does not reduce risk. The commenter states 

that the EPA’s own technical analysis indicates that removal of 

the 0.9 Mg/yr benzene alternative would have no effect on the 

MIR. 

Secondly, the commenter states that the EPA’s cost analysis 

is severely flawed. The EPA concludes that the cost 
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effectiveness of the proposed removal of the 0.9 Mg/yr benzene 

compliance alternative for natural gas transmission and storage 

facilities is reasonable. However, the cost estimates used by 

the EPA in the ample margin of safety determination are 

inadequate. The EPA did not conduct any analysis using actual 

data. Rather, the EPA used costs estimated for small dehydrators 

and made general assumptions to estimate an upper-end cost 

effectiveness for removing the 0.9 Mg/yr benzene alternative 

limit for large dehydrators at natural gas transmission and 

storage facilities. The commenter believes that, in general, the 

emission reductions for dehydrators forced to switch from the 

0.9 Mg/yr benzene alternative to 95% control would be 

considerably less than those achieved by small dehydrators. The 

cost effectiveness calculated for small dehydrators is based on 

a 95% reduction from an uncontrolled baseline level. If a large 

dehydrator has installed controls to meet the 0.9 Mg/yr 

alternative benzene limitation, the cost effectiveness must be 

based on the incremental reduction between the existing controls 

and 95%. The EPA has provided no evidence that these incremental 

reductions would be greater than or equal to the 95% reductions 

that would be achieved for smaller dehydrators. In conclusion,

the commenter states that the rationale used by the EPA in the 

preamble to support the removal of the 0.9 Mg/yr compliance 

alternative for dehydrators at natural gas transmission and 
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storage facilities under 112(f)(2) of the CAA is not supported 

by any of the background technical documentation and analyses. 

The commenter believes that the EPA has no basis under any other 

CAA authority for this action.

Response: In response to comments, we re-examined our risk 

assessment for the Natural Gas Transmission and Storage source 

category and discovered that the two facilities8 we identified as 

the risk drivers are area sources and not part of this major 

source category that is the subject of this section 112(j)(2) 

review. We are including the 0.9 Mg/yr benzene compliance 

alternative in the final amendments for subpart HHH. See 

additional discussion above in section VII.B

C. Major comments concerning the previously unregulated sources

Comment: Two commenters do not believe that the dataset used is 

representative of currently operating small glycol dehydrators.

One commenter recommends that the EPA base its MACT floor 

analyses on emissions data from a representative population of 

small dehydrators that characterize the population of affected 

sources within the category or subcategory. The commenter 

reports that more current data sources may be available, such as 

dehydrator emissions data reported to state agencies in annual 

emission reports or in permit applications.

 

8 Bradley Compressor Station and Danville Compressor Station. Both in West 

Virginia.
Page 156 of 497

One commenter opines that the EPA’s proposal misses the 

opportunity and fails to fulfill the agency’s responsibility to 

properly calculate the MACT for all sources in this sector based 

on current, reliable, and representative emission test data. The 

commenter believes that, by relying on an incomplete and 

outdated dataset to set MACT floors and limits, the EPA has 

ignored data demonstrating trends in practices, processes and 

technologies and the resulting improved performance that section 

112(d) mandates. The commenter asserts that the EPA ignores the 

potential HAP emissions that the control devices themselves emit 

by failing to collect such emissions data from facilities that 

have installed control devices. The commenter argues that the 

EPA must collect the appropriate emission test data needed in 

order to recalculate and set a proper MACT for glycol 

dehydrators, storage vessels, and equipment leaks. 

One commenter states that section 112 of the CAA requires 

the EPA to set a NESHAP for each category or subcategory of 

“major sources” of HAP emissions. 42 U.S.C. § 7412(d)(1). The 

commenter asserts that the EPA must set section 112(d) emission 

standards based on “maximum achievable control technology” or 

“MACT.” The commenter states that the EPA largely bases its MACT 

proposal for small glycol dehydrators on emissions data 

collected from the industry during the development of the 

original MACT standards. 76 FR 52,768. The commenter contends 
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that the data were collected prior to 1997 and did not 

adequately represent the emissions profile at that time, and do

not reflect the significant changes in the industry and other 

technological developments that have occurred during the past 13 

years. According to the commenter, the EPA has not provided a 

reasoned explanation of how those data could be representative 

of currently operating glycol dehydrators and associated 

emission reductions, and how proposals based on those data can 

currently meet the MACT requirements for new and existing 

sources. The commenter states that the dehydrator technology 

performance in 1997 was not accurately reflected in the legacy 

EPA dataset and has advanced significantly in the past thirteen 

years. 

One commenter states that the EPA did not collect recent 

data regarding emissions of HAPs, including BTEX, from small 

glycol dehydrators in either source sector in support of this 

rulemaking. Instead, according to the commenter, the EPA appears 

to have relied on data collected in the prior MACT rulemaking, 

going back to 1998 or prior. The commenter believes that the 

EPA’s analysis is flawed and questionable because it simply 

relies on the best-performing sources that existed a decade ago 

and fails to identify the best controlled sources today. The 

commenter contends that it is unlikely that these MACT standards 

reflect either the current best controlled similar source 
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emissions or the average of the top 12 percent of the currently 

best controlled sources. The commenter states that while the EPA 

appropriately proposes to set a MACT limit for these sources for 

the first time, the EPA’s use of out-dated data fails to 

demonstrate that its proposed limit is stringent enough in light 

of significant developments in emission control technologies and 

practices that have occurred since 1998. 

Response: The commenters claim that the data the EPA used to set 

the MACT standards for the small glycol dehydrators subcategory 

are outdated and that the EPA must collect new data. However, 

section 112(d)(2) and (3), under which the EPA is setting these 

standards, do not require that the EPA collect information. 

Rather, section 112(d)(3) allows the EPA to calculate the MACT 

floors based on information that the EPA has. Although the 

information is over a decade old, the available controls for 

reducing emissions from small glycol dehydrators and their 

control efficiencies have remained the same during this period

and the commenters have not given any indication to the 

contrary. We therefore believe the data we have are still 

representative of the performance of the small dehydrators.

The small dehydrators are left uncontrolled under the 

current NESHAP. Collection and analysis of additional data would 

inevitably take time and further delay control of these sources. 

We do not believe such delay is warranted, in light of the fact 
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that we think the data we have are still representative of these 

sources’ performance today. For the reasons stated above, we 

believe it is reasonable for us to set MACT standards based on 

these data instead of collecting more current data.

We considered using more current data (i.e., the 2005 NEI), 

however, this dataset lacks specific information we believe 

relevant to identify the best performing units. For glycol 

dehydrators, the best performing units were not necessarily 

represented by those units with the lowest emissions. Low 

natural gas throughput and low inlet HAP content can be the 

primary factors in a source’s low emissions. We do not believe 

sources with inherently low throughput and/or inlet HAP content 

necessarily comprise the best performing sources. Therefore, we

used the 1997 data which contained that information. We were not 

able to identify any readily available data source that included 

inlet gas concentration and throughput, along with other data 

needed to calculate emissions. As a result we used the data 

collected for the 1999 MACT standards.

D. Major comments concerning the technology review

1. Representative of current technology and level of emissions

Comment: One commenter states that, in conducting an 8-year 

review, the EPA must “look back” at the earlier standard and 

ascertain whether: 1) the standard was adopted using procedures 

that comply with the law as it has come to be interpreted by the 
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courts; 2) the EPA had sufficiently accurate and comprehensive 

data at the time of the initial standard setting respecting the 

emissions profile of the category and properly identified the 

best performing unit(s); and 3) the EPA had properly used the 

available data.

The commenter states the EPA then must “look around” using 

currently available data and determine whether: 1) the emissions 

profile of the industry has changed in a way that would 

substantially affect the MACT floor calculations (the commenter 

adds that this includes consideration of any increase in the 

number of good performing units available for use in the 

existing source MACT floor calculation and in the performance of 

the best performing unit); 2) data gaps or uncertainties that 

affected the earlier decision have been resolved in the interim 

or can be resolved using new information available to the 

agency; 3) costs or other factors have changed in a way that 

would substantially affect the “beyond the floor” determination; 

4) the use of improved practices, processes or technologies 

(including improvements in the performance of existing 

technologies) has become more prevalent than at the time of the 

initial standard setting; or 5) whether newer regulatory 

requirements, work practices or emission limitations (including 

state and local jurisdiction air pollution standards and federal 

enforcement actions), which are more stringent than the existing 
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112(d) standard, have shown the achievement or achievability of 

greater emission reductions than the existing standard requires.

Response: We disagree with the commenter’s interpretation of 

section 112(d)(6) requirements. While we appreciate the 

commenter’s ideas on how the 112(d)(6) analysis could be 

conducted, nowhere does 112(d)(6) require any such “look back” 

or “look around” analysis as the commenter contends. The 

commenter appears to argue that 112(d)(6) requires that the EPA 

recalculate the MACT based on current data and technology. The 

same argument was posed to the D.C. Circuit, and the Court 

“[did] that think that the words ‘review, and revise as 

necessary’ can be construed reasonably as imposing any such 

obligation.” NRDC v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008).

2. Glycol dehydration units and storage vessels

Comment: One commenter states that the EPA’s technology review 

for storage vessel control technologies is limited and makes 

incorrect assumptions. The commenter contends that without 

further support, the public cannot understand and the EPA cannot 

justify its proposed decision; therefore, the EPA’s proposal is 

arbitrary and capricious. The commenter adds that the EPA must 

conduct an updated beyond-the-floor analysis for both newly 

controlled emission points, and the EPA must determine a proper 

beyond-the-floor MACT level for storage vessels, by determining 

the “maximum degree of reduction in emissions” that is 
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achievable, as required under section 112(d)(2). The commenter 

states that the proposed rule fails to provide any discussion of 

a beyond-the-floor determination for storage vessels.

One commenter states that the EPA must examine advances in 

vapor recovery unit technology and reconsider floating roof 

technology for tanks containing liquids that do not have the 

potential for flash emissions. The commenter contends that the 

EPA improperly rejected technology advances and developments in 

pollution prevention systems found in its own RBLC database and 

employed by its own Natural Gas STAR partners. Specifically, 

according to the commenter, the EPA failed to evaluate the 

performance achieved by systems that use thermal or catalytic 

oxidizers, either alone or in combination with condensers. 

According to the commenter, the EPA’s RBLC review identified a 

BACT determination for dehydrator efficiency of 98 percent. The 

commenter also urges the EPA to evaluate the use of combustion 

devices and vapor recovery units that capture vent steam from 

the tank and turn it into a saleable product by recompressing 

the hydrocarbon vapors. The commenter contends that the EPA 

rejects technology advances by asserting that those technologies 

were considered in the 1999 rulemaking, but fails to provide 

support for its decision in either the record of the 1999 

rulemaking or the current record. The commenter contends that 

the EPA must provide a basis for its decisions and conclusions.
Page 163 of 497

Response: We disagree with the commenter. The EPA has determined 

that the technology review provisions for NESHAP under section 

112(d)(6) must take into account the cost of controls. In the 

technology review process, we evaluated additional control 

options for storage vessels and found that none was cost 

effective. In addition, none of the storage vessels at the major 

sources used to evaluate the MACT floor used floating roofs.

E. Major comments concerning notification, recordkeeping and 

reporting requirements

1. Annual reports

Comment: One commenter requested that the EPA add a selfcertification requirement to the annual report similar to that 

used in the title V program. The commenter recommended that the 

final rule require the annual report to include a statement 

signed by a senior official of the facility attesting to the 

truth, accuracy and completeness of the report.

The commenter also requested that the EPA require that the 

annual reports be submitted electronically to facilitate making 

the reports publicly available. The commenter suggested using 

social media outlets, smart phone applications, and other 

electronic means to make the annual reports readily available. 

Response: The EPA agrees that self-certification is an important 

mechanism for assuring the public that the information submitted 

by each facility is accurate. In addition, the title V program 
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has successfully employed self-certification for since its 

inception. Therefore, we are requiring self-certification, based 

on requirements in the title V program, in the final rule.

While we agree that having annual reports readily available 

to the public is a desirable goal, we did not identify any 

reporting programs or electronic databases that may be used for 

this purpose without significant modification. Therefore, we are 

not requiring annual reports to be submitted electronically, but 

we will continue to evaluate this option in the future.

2. Electronic reporting of emissions data

Comment: Several commenters raised similar issues regarding 

reporting of emissions data under the NESAHP as under the NSPS, 

described supra, and our responses there apply equally here. 

Please see comments and responses in section IX.G.3.

XI. What are the cost, environmental, and economic impacts of 

the final NESHAP/NSPS amendments?

A. What are the air 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 technologies selected 

by the engineering analysis. These emission reductions 

associated with the final amendments to 40 CFR part 63, subpart 

HH and 40 CFR part 63, subpart HHH are based on the estimated 
Page 165 of 497

population in 2008. Under the finalized limits for glycol 

dehydration units and storage vessels, we have estimated that 

the HAP emissions reductions will be 1,300 tpy for existing 

units subject to the final 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 final NSPS, we have estimated that the emissions 

reductions will be 290,000 tpy VOC for affected facilities 

subject to the NSPS.

The control strategies likely adopted to meet the final 

NESHAP amendments and the final NSPS will result in concurrent 

control of HAP, methane and VOC emissions. We estimate that 

direct reductions in HAP, methane and VOC for the final rules 

combined total about 20,000 tpy, 1.7 million tpy, and 300,000 

tpy, respectively.

The EPA received several comments regarding the emission 

factor selected to calculate whole gas emissions (and the 

associated VOC emissions) from hydraulically fractured well 

completions. Comments focused on the data behind the emission 

factor, what the emission factor is intended to represent, and 

the procedures used to develop the emission factor from the 
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selected data sets. We reviewed all information received and 

have decided to retain the data set and the analysis conducted 

to develop the emission factor of 9,000 Mcf per completion. More 

detailed discussion is presented in a technical memorandum on 

this subject in the docket.

B. 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 environmental controls analyzed under the final NESHAP 

amendments and final NSPS.

The final NESHAP amendments and final 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 production process for sale. We estimated 

that the final standards will result in net annual costs savings 

of about $60,000 (in 2008 dollars) due to the recovery of 

salable natural gas and condensate. Thus, the final standards 

have a positive impact associated with the recovery of nonrenewable energy resources.

C. What are the cost impacts?
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The estimated total capital cost to comply with the final 

amendments to 40 CFR part 63, subpart HH for major sources in 

the Oil and Natural Gas Production source category is 

approximately $47 million. The total capital cost for the final 

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 final amendments to 40 CFR part 63, subpart HH for 

major sources in the Oil and Natural Gas Production source 

category is approximately $18 million. The total net annual cost 

for final 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 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 final 

NSPS is approximately $340 million in 2008 dollars. The total 

estimated net annual cost to industry to comply with the final 

NSPS is approximately $340 million in 2008 dollars. This annual 
Page 168 of 497

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 final 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 82 million Mcf (82 billion cubic feet) of 

natural gas and 320,000 barrels of 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 $350 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 final 

NSPS at about $18 million in 2008 dollars. Totals may not sum 

due to independent rounding.
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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 final 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 -$36 

million, which would approximately double the estimate of net 

cost savings of the final NSPS. As indicated by this difference, 

the EPA has chosen a relatively conservative assumption (leading 

to an estimate of few savings and higher net costs) for the 

engineering costs analysis. The natural gas price at which the 

final NSPS breaks-even from an estimated engineering costs 

perspective is around $3.79/Mcf. A $1/Mcf change in the wellhead 

natural gas price leads to a $82 million change in the 

annualized engineering costs of the final NSPS. Consequently, 

annualized engineering costs estimates would increase to about 

$65 million under a $3/Mcf price or decrease to about -$100 

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.

D. What are the economic impacts?

The analysis of energy system impacts for the final NSPS 

estimates that domestic natural gas production is likely to 
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increase slightly (about 60 billion cubic feet or 0.3 percent) 

and average natural gas prices to decrease slightly ($0.05 per 

Mcf in 2008 dollars or 1.2 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 oil prices are estimated to decrease slightly 

($0.01/barrel in 2008 dollars or about 0.01 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 will 

decrease slightly (about 10 bcf or 0.4 percent) and crude will 

not change significantly. 

Total CO2e emissions from energy-related sources are 

expected to increase about 540 thousand metric tons CO2e or about 

0.01 percent under the final NSPS, according to the NEMS 

analysis. This increase is attributable largely to natural gas 

consumption increases, although these increases are estimated to 

be partially offset by declines in petroleum and coal 

consumption. 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.
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We did not estimate the energy economy impacts of the final 

NESHAP amendments using NEMS, as the expected costs of the rule 

are not likely to have estimable impacts on the national energy 

economy.

E. What are the benefits of this final rule?

The final 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 final rules combined are anticipated to reduce 

20,000 tons of HAP, 300,000 tons of VOC (a precursor to both 

PM2.5 and ozone formation) and 1.7 million tons of methane (a 

GHG and a precursor to global ozone formation). 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 
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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 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. VOC emissions are precursors to both PM2.5 and 

ozone formation. As documented in previous analyses (U.S. EPA, 

20069 and U.S. EPA, 201010), exposure to PM2.5 and ozone is 

associated with significant public health effects. PM2.5 is 

associated with health effects, including premature mortality 

for adults and infants, cardiovascular morbidity such as heart 

attacks, and respiratory morbidity such as asthma attacks, acute 

 

9 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>.

10 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>.
Page 173 of 497

and chronic bronchitis, hospital admissions and emergency room 

visits, work loss days, restricted activity days and respiratory 

symptoms, as well as visibility impairment.11 Ozone is associated 

with health effects, including hospital and emergency department 

visits, school loss days and premature mortality, as well as 

injury to vegetation and climate effects.12 

In addition to the improvements in air quality and 

resulting benefits to human health and non-climate welfare 

effects previously discussed, this 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 globally. Total methane emissions from the oil 

and gas industry represent about 40 percent of the total 

 

11 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>.

12 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.
Page 174 of 497

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.13 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 requires emission control technologies and 

regulatory alternatives that will significantly decrease HAP and 

VOC emissions from the oil and natural gas sector in the United 

States. As a co-benefit, the emission control measures the 

industry will use to reduce HAP and VOC emissions will also 

decrease methane emissions. The NESHAP Amendments and the NSPS 

combined are expected to reduce methane emissions annually by 

about 1.7 million short tons or about 33 million metric tons 

CO2e. After considering the secondary impacts of this rule 

previously discussed, such as increased CO2 emissions from well 

completion combustion and decreased CO2e emissions because of 

fuel-switching by consumers, the methane reductions become about 

 

13 U.S. EPA (2011), 2011 U.S. Greenhouse Gas Inventory Report Executive 

Summary available on the internet at 

http://epa.gov/climatechange/emissions/downloads11/US-GHG-Inventory-2011-

Executive-Summary.pdf, accessed 02/13/12.
Page 175 of 497

31 million metric tons CO2e. The methane reductions represent 

about 13 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). However, it is 

important to note that the emission reductions are based upon 

predicted activities in 2015; the EPA did not forecast sectorlevel emissions in 2015 for this rulemaking. These emission 

reductions equate to the climate benefits of taking 

approximately 6 million typical passenger cars off the road or 

eliminating electricity use from about 4 million typical homes 

each year.14

The EPA recognizes that the methane reductions from this 

rule will provide for significant economic climate benefits to 

society just described. However, the 2009-2010 Interagency 

Social Cost of Carbon Work Group did not produce directly

modeled estimates of the social cost of methane. In the absence 

of direct model estimates from the interagency analysis, the EPA 

has used a “global warming potential (GWP) approach” to estimate 

the dollar value of this rule’s methane co-benefits. 

Specifically, the EPA converted methane to CO2 equivalents using 

 

14 U.S. EPA. Greenhouse Gas Equivalency Calculator available at: 

http://www.epa.gov/cleanenergy/energy-resources/calculator.html, accessed 

02/13/12.
Page 176 of 497

the GWP of methane, then multiplied these CO2 equivalent emission 

reductions by the social cost of carbon developed by the 

Interagency Social Cost of Carbon Work Group.

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 1286615 Applying 

this approach to the methane reductions estimated for the NESHAP 

Amendments and NSPS, the 2015 climate co-benefits vary by 

discount rate and range from about $190 million to 

approximately $2.4 billion; the mean social cost of carbon at 

the 3-percent discount rate results in an estimate of about $780 

million in 2015.16

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-

 

15 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-OAR2009-0472-114577. http://www.epa.gov/otaq/climate/regulations/scctsd.pdf, accessed 02/12/12.

16 The ratio of domestic to global benefits of emission reductions 

varies with key parameter assumptions. See Interagency Working Group 

on Social Cost of Carbon. 2010. Technical Support Document: Social 

Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866.
Page 177 of 497

percent discount rate. 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 short-lived 

climate forcer that contributes to global warming. The use of 

the IPCC Second Assessment Report GWP to 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 the 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.17 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 

 

17 Marten and Newbold (2011), Estimating the Social Cost of Non-CO2 GHG 

Emissions: Methane and Nitrous Oxide, NCEE Working Paper Series #11-

01. http://yosemite.epa.gov/EE/epa/eed.nsf/WPNumber/2011-

01?OpenDocument.
Page 178 of 497

lower value of 21 used in this analysis. Using the higher GWP 

estimate of 25 would increase these reported methane climate cobenefit 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 from the IPCC Second Assessment Report to 

estimate the methane climate co-benefits for this oil and gas 

proposal. The EPA uses the 21 GWP 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 approach” 

estimates presented and methane climate co-benefits 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. 

For the final NESHAP amendments, a break-even analysis 

suggests that HAP emissions would need to be valued at $14,000 

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 final 

NESHAP amendments, they are legitimate components of the total 
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benefit-cost comparison. If we assume the health benefits from 

HAP emission reductions are zero, the VOC emissions would need 

to be valued at $1,900 per ton or the methane emissions would 

need to be valued at $3,700 per ton for the co-benefits to 

exceed the costs. All estimates are in 2008 dollars. For the 

final NSPS, the revenue from additional product recovery exceeds 

the costs, which renders a break-even analysis unnecessary when 

these revenues are included in the analysis. Based on the 

methodology from Fann, Fulcher, and Hubbell (2009),18 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 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.

 

18 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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XII. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review and 

Executive Order 13563, Improving Regulation and Regulatory 

Review

Under section 3(f)(1) of 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 the Office of Management and Budget 

(OMB) for review under Executive Orders 12866 and 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 Regulatory Impact Analysis (RIA) 

of the potential costs and benefits associated with this action. 

The RIA 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 3 shows the results of the cost and benefits analysis for 

these final rules. 

TABLE 3. SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND 

NET BENEFITS FOR THE FINAL OIL AND NATURAL GAS NSPS AND NESHAP 

AMENDMENTS IN 2015 (MILLIONS OF 2008$)1

Final NSPS Final NESHAP 

Amendments

Final NSPS and 

NESHAP 

Amendments 
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Combined

Total 

Monetized 

Benefits2

N/A N/A N/A

Total Costs3 -$18 million $18 million -$61,000

Net Benefits N/A N/A N/A

Nonmonetized 

Benefits4

19,000 tons of 

HAPs

1,300 tons of 

HAPs

20,000 tons of 

HAPs

290,000 tons of 

VOCs

9,000 tons of 

VOCs

300,000 tons of 

VOCs

1.7 million tons 

of methane

4,800 tons of 

methane

1.7 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 final NSPS 

reflects the inclusion of revenues from additional natural gas 

and hydrocarbon condensate recovery that are estimated as a 

result of the NSPS.

4 For the NSPS, reduced exposure to HAP and climate effects are 

co-benefits. For the NESHAP, reduced VOC emissions, PM2.5 and 

ozone exposure, visibility and vegetation effects and climate 

effects are co-benefits.

5 The specific control technologies for these final rules are 

anticipated to have minor secondary disbenefits. The net CO2-

equivalent emission reductions are 90,000 metric tons for the 

NESHAP and 31 million metric tons for the NSPS.

B. Paperwork Reduction Act
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The information collection requirements in this rule have 

been submitted for approval to OMB under the PRA, 44 U.S.C. 

3501, et seq. The ICR documents prepared by the EPA has been 

assigned EPA ICR numbers 2437.01, 2438.01, 2439.01, and 

2440.01. 

The information collection requirements are not enforceable 

until OMB approves them. The information requirements are based 

on notification, recordkeeping, and reporting requirements in 

the NESHAP General Provisions (40 CFR part 63, subpart A), which 

are mandatory for all operators subject to national emission 

standards. These recordkeeping and reporting requirements are 

specifically authorized by CAA section 114 (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. This final rule requires maintenance 

inspections of the control devices but would not require any 

notifications or reports beyond those required by the General 

Provisions. The recordkeeping requirements require only the 

specific information needed to determine compliance. 

When a malfunction occurs, sources must report them 

according to the applicable reporting requirements of 40 CFR 

part 63, subpart HH or 40 CFR part 63, subpart HHH. An 

affirmative defense to civil penalties for exceedances of 
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emission limits that are caused by malfunctions is available to 

a source if it can demonstrate that certain criteria and 

requirements are satisfied. 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 reasonable preventable, and not caused by poor maintenance 

and or careless operation) and where the source took necessary 

actions to minimize emissions. In addition, the source must meet 

certain notification and reporting requirements. For example, 

the source must prepare a written root cause analysis and submit 

a written report to the Administrator documenting that it has 

met the conditions and requirements for assertion of the 

affirmative defense. 

For this rule, the EPA is adding affirmative defense to the 

estimate of burden in the ICR. To provide the public with an 

estimate of the relative magnitude of the burden associated with 

an assertion of the affirmative defense position adopted by a 

source, the EPA has provided administrative adjustments to this 

ICR that shows what the notification, recordkeeping, and 

reporting requirements associated with the assertion of the 

affirmative defense might entail. The EPA’s estimate for the 

required notification, reports, and records, including the root 

cause analysis, associated with a single incident totals 
Page 184 of 497

approximately totals $3,141, and is based on the time and effort 

required of a source to review relevant data, interview plant 

employees, and document the events surrounding a malfunction 

that has caused an exceedance of an emission limit. The estimate 

also includes time to produce and retain the record and reports 

for submission to the EPA. The EPA provides this illustrative 

estimate of this burden, because these costs are only incurred 

if there has been a violation, and a source chooses to take 

advantage of the affirmative defense. 

The EPA provides this illustrative estimate of this burden 

because these costs are only incurred if there has been a 

violation and a source chooses to take advantage of the 

affirmative defense. Given the variety of circumstances under 

which malfunctions could occur, as well as differences among 

sources’ operation and maintenance practices, we cannot reliably 

predict the severity and frequency of malfunction-related excess 

emissions events for a particular source. It is important to 

note that the EPA has no basis currently for estimating the 

number of malfunctions that would qualify for an affirmative 

defense. Current historical records would be an inappropriate 

basis, as source owners or operators previously operated their 

facilities in recognition that they were exempt from the 

requirement to comply with emissions standards during 

malfunctions. Of the number of excess emissions events reported 
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by source operators, only a small number would be expected to

result from a malfunction (based on the definition above), and 

only a subset of excess emissions caused by malfunctions would 

result in the source choosing to assert the affirmative defense. 

Thus, we believe the number of instances in which source 

operators might be expected to avail themselves of the 

affirmative defense will be extremely small. 

For this reason, we estimate 39 such occurrences for all 

sources subject to 40 CFR part 63, subpart HH and one such 

occurrence for all sources subject to 40 CFR part 63, subpart 

HHH over the 3-year period covered by this ICR. We expect to 

gather information on such events in the future, and will revise 

this estimate as better information becomes available. 

The annual monitoring, reporting, and record-keeping burden 

for this collection (averaged over the first 3 years after the 

effective date of the standards) is estimated to be $2.4 

million. This includes 61,249 labor hours per year at a total 

labor cost of $2.1 million per year, and annualized capital 

costs of $0.22 million, and annual operating and maintenance 

costs of $0.08 million. This estimate includes initial and 

annual performance tests, semiannual excess emission reports, 

developing a monitoring plan, notifications, and recordkeeping. 

All burden estimates are in 2008 dollars and represent the most 
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cost effective monitoring approach for affected facilities. 

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. When these ICRs are approved by OMB, the agency will 

publish a technical amendment to 40 CFR part 9 in the Federal 

Register to display the OMB control numbers for the approved 

information collection requirements contained in the final rule.

C. Regulatory Flexibility Act as Amended by the Small Business 

Regulatory Enforcement Fairness Act (RFA) of 1996 (SBREFA), 5 

U.S.C. 601 et seq.

The Regulatory Flexibility Act generally requires an agency 

to prepare a regulatory flexibility analysis of any rule subject 

to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute, unless the 

agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities 

(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 as defined by 

NAICS codes 211111, 211112, 221210, 486110 and 486210; whose 
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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.

For the final NSPS, the EPA performed an 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, when revenue from 

additional natural gas product recovered is not included, we 

estimate that 120 of the 127 small firms analyzed (94 percent) 

are likely to have impacts less than 1 percent in terms of the 

ratio of annualized compliance costs to revenues. Meanwhile, 

seven firms (6 percent) are likely to have impacts greater than 

1 percent. Three of these seven firms are likely to have impacts 

greater than 3 percent. However, when revenue from additional 

natural gas product recovery is included, we estimate that none 

of the analyzed firms will have an impact greater than 1 

percent.

For the final NESHAP Amendments, we estimate that 54 of the 

108 firms (50 percent) that own potentially affected facilities 
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are small entities. The EPA performed an analysis for impacts on 

all expected affected small entities by comparing compliance 

costs to entity revenues. Among the small firms, 45 of the 54 

(83 percent) are likely to have impacts of less than 1 percent 

in terms of the ratio of annualized compliance costs to 

revenues. Meanwhile, nine firms (17 percent) are likely to have 

impacts greater than 1 percent. Three of these nine firms are 

likely to have impacts greater than 3 percent. While these nine 

firms might receive significant impacts from the final 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. 

After considering the economic impact of the combined NSPS 

and NESHAP amendments on small entities, I certify this action 

will not have a SISNOSE. While both the NSPS and NESHAP 

amendment would individually result in a no SISNOSE finding, the 

EPA performed an additional analysis in order to certify the 

rule in its entirety. This analysis compared compliance costs to 

entity revenues for the total of all the entities affected by 

the NESHAP amendments and the sample of entities analyzed for 

the NSPS. When revenues from additional natural gas product 

sales are not included, 153 of the 169 small firms (91 percent) 

in the sample are likely to have impacts of less than 1 percent 

in terms of the ratio of annualized compliance costs to 
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revenues. Meanwhile, 16 firms (9 percent) are likely to have 

impacts greater than 1 percent. Six of these 16 firms are likely 

to have impacts greater than 3 percent. When revenues from 

additional natural gas product sales are included, 160 small 

firms (95 percent) in the sample are likely to have impacts of 

less than 1 percent. Nine firms (5 percent) are likely to have 

impacts greater than 1 percent, while only three of these nine 

are likely to have impacts greater than 3 percent. 

Our 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 wellrelated 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.

Our current baseline for the impacts analysis of our NSPS 

for gas well completions takes into account reduced emission 
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completions conducted pursuant to state regulations covering

these operations. However, based on public comments and reports 

to the EPA's Natural Gas Star program, the EPA acknowledges that 

some producers conduct well completions using REC techniques 

voluntarily. However, the EPA normally does not account for 

voluntary actions in baseline emissions estimates when we 

analyze potential impacts of our regulatory actions, since there 

is no assurance that such voluntary emission reduction measures 

will continue in the future. As such, emissions reductions 

obtained from RECs implemented voluntarily are not reflected in 

our baseline emissions estimates.

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.

D. Unfunded Mandates Reform Act of 1995

This final action does not contain a federal mandate under 

the provisions of Title II of the Unfunded Mandates Reform Act 

of 1995 (UMRA), 2 U.S.C. 1531-1538 for state, local, and tribal 

governments, in the aggregate, or to the private sector. The 

action would not result in expenditures of $100 million or more 

for state, local, and tribal governments, in the aggregate, or 
Page 191 of 497

to the private sector in any 1 year. Thus, this final rule is 

not subject to the requirements of sections 202 or 205 of UMRA.

This final 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 because it contains no requirements that apply to 

such governments nor does it impose obligations upon them.

E. Executive Order 13132: Federalism

This action 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. These final rules primarily affect private industry, and 

do not impose significant economic costs on state or local 

governments. Thus, Executive Order 13132 does not apply to this 

action. 

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

Subject to the Executive Order 13175 (65 FR 67249, November 

9, 2000) EPA may not issue a regulation that has tribal 

implications, that imposes substantial direct compliance costs, 

and that is not required by statute, unless the Federal 

government provides the funds necessary to pay the direct 
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compliance costs incurred by tribal governments, or EPA consults 

with tribal officials early in the process of developing the 

proposed regulation and develops a tribal summary impact 

statement.

EPA has concluded that this action will have tribal 

implications because of the growth of the oil and gas production 

industry in Indian country.

The EPA consulted with tribal officials early in the 

process of developing this regulation to permit them to have 

meaningful and timely input into its development. Outreach was 

conducted prior to the proposal in 2010. The EPA met with the 

Inter Tribal Environmental Council, which include many of the 

Region VI tribes, The Tribal leadership summit in Region X, and 

Tribal Energy Conference hosted by Ft. Belknap, and the National 

Tribal Forum. 

After the proposal was published, letters were sent to all 

tribal leaders offering to consult on the rule. An outreach and 

consultation call was held on October 12, 2011. Tribes that 

participated on this call were: Fond du Lac Band of Lake 

Superior Chippewa, Fort Belknap Indian Community, Forest County 

Potawatomi Community, Southern Ute Indian Tribe, and Pueblo of 

Santa Clara. All these tribes counted this as information only, 

not consultation. There were no issues raised during this call. 
Page 193 of 497

The tribes were listening to the presentation and the call was 

ended without comment.

In this meeting the tribes were presented the information 

in the proposal then asked general clarifying questions but did 

not provide specific comments. Comments on the proposal were 

received from an affiliate of the Southern Ute Indian Tribe. 

The commenter expressed concern about the impacts of the rule on 

natural gas and oil production operations on the Southern Ute 

Indian reservation and requested additional time to evaluate the 

impacts. In response to this and other requests, the comment 

period was extended. More specific comments can be found in the 

docket. 

As required by section 7(a), the EPA’s Tribal Consultation 

Official has certified that the requirements of the Executive 

Order have been met in a meaningful and timely manner. A copy of 

the certification is included in the docket for this action.

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

This action 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 action 

would not relax the control measures on existing regulated 

sources. The EPA’s risk assessments (included in the docket for 
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this final rule) demonstrate that the existing regulations are 

associated with an acceptable level of risk and provide an ample 

margin of safety to protect public health. 

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

This action is not a “significant energy action” as defined 

in Executive Order 13211 (66 FR 28355, (May 22, 2001)), because 

it is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. These final 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 final NESHAP amendments are unlikely to have a 

significant adverse effect on the supply, distribution, or use 

of energy. As such, the final NESHAP amendments are not 

“significant energy actions” as defined in Executive Order 

13211, (66 FR 28355, May 22, 2001). 

The final NSPS is also unlikely to have a significant 

adverse effect on the supply, distribution, or use of energy. As 

such, the final NSPS is not a “significant energy action” as 

defined in Executive Order 13211 (66 FR 28355, May 22, 2001). 

The basis for the determination is as follows.

We use the NEMS to estimate the impacts of the final NSPS 

on the United States energy system. The NEMS is a publically 

available model of the United States energy economy developed 
Page 195 of 497

and maintained by the Energy Information Administration of the 

U.S. DOE and is used to produce the Annual Energy Outlook, a 

reference publication that provides detailed forecasts of the 

United States energy economy. 

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 final NSPS 

also captures saleable condensates. The revenues from 

additional natural gas and condensate recovery are expected to 

offset the costs of implementing the final NSPS. 

The analysis of energy impacts for the final NSPS that 

includes the additional product recovery shows that domestic 

natural gas production is estimated to increase (about 60 

billion cubic feet or 0.3 percent) and natural gas prices to 

decrease ($0.05/Mcf or 1.2 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 ($0.01/barrel or less 

than about 0.01 percent at the wellhead for producers in the 

lower 48 states) in 2015, the year of analysis. All prices are 

in 2008 dollars.
Page 196 of 497

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 final 

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 NTTAA of 1995, Public Law 104–113, 

12(d) (15 U.S.C. 272 note) directs the EPA to use VCS in its

regulatory activities unless to do so would be inconsistent with 

applicable law or otherwise impractical. Voluntary consensus 

standards are technical standards (e.g., materials 

specifications, test methods, sampling procedures, and business 

practices) that are developed or adopted by VCS bodies. The 

NTTAA directs the EPA to provide Congress, through OMB, 

explanations when the EPA decides not to use available and 

applicable VCS. 

This final action does not involve technical standards. 

Therefore, the EPA is not considering the use of any VCS.
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J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes Federal executive policy on environmental justice. 

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.

The EPA has determined that this final 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, low-income, or indigenous 

populations. 

To examine the potential for any environmental justice 

issues that might be associated with each source category, we 

evaluated the percentages of various social, demographic, and 

economic groups within the at-risk population living near the 
Page 198 of 497

facilities where these source categories are located and 

compared them to national averages. The development of 

demographic analyses to inform the consideration of 

environmental justice issues in the EPA rulemakings is an 

evolving science. 

The EPA conducted a demographic analysis, focusing on 

populations within 50 km of any facility in each of the source 

categories that are estimated to have HAP exposures which result 

in cancer risks of 1-in-1 million or greater or non-cancer 

hazard indices of 1 or greater based on estimates of current HAP 

emissions. The results of this analysis are documented in the 

technical report: Risk and Technology Review – Analysis of 

Socio-economic Factors for Populations Living Near Oil & Natural 

Gas Production Facilities located in the docket for this 

rulemaking.

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 or human health multipathway effects, and that acute and chronic noncancer health 
Page 199 of 497

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.

To promote meaningful involvement, the EPA conducted three 

public hearings on the proposal. The hearings were held in 

Pittsburgh, PA on September 27, 2011, Denver, CO on September 

28, 2011 and Arlington, TX on September 29, 2011. A total of 261 

people spoke at the three hearings and 735 people attended the 

hearings. The attendees at the hearings included private 

citizens, community-based and environmental organizations, 

industry representatives, associations representing industry and 

local and state government officials.

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801, et seq., as 

added by the Small Business Regulatory Enforcement Fairness Act 

of 1996, generally provides that before a rule may take effect, 

the agency promulgating the rule must submit a rule report, 

which includes a copy of the rule, to each House of the Congress

and to the Comptroller General of the United States. The EPA 

will submit a report containing this final rule and other 

required information to the United States Senate, the United 

States House of Representatives, and the Comptroller General of 

the United States prior to publication of the final rule in the 
Page 200 of 497

Federal Register. A major rule cannot take effect until 60 days 

after it is published in the Federal Register. This action is a 

“major rule” as defined by 5 U.S.C. 804(2). The final rules will 

be effective on [INSERT DATE 60 DAYS AFTER THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER].
Page 201 of 497

Oil and Natural Gas Sector: New Source Performance Standards and 

National Emission Standards for Hazardous Air Pollutants Reviews

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, Administrative practice and 

procedures, Air pollution control, Hazardous substances, 

Incorporation by reference, Reporting and recordkeeping 

requirements, Volatile organic compounds.

____________________________

Dated:

____________________________

Lisa P. Jackson,

Administrator.
Page 202 of 497

For the reasons set out in the preamble, title 40, chapter 

I of the Code of Federal Regulations is 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).

(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).
Page 203 of 497

* * * * *

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 August 23, 2011

3. The heading for Subpart KKK is revised to read 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 August 23, 

2011, 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 August 23, 2011

5. The heading for Subpart LLL is revised to read 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.

* * * * *
Page 204 of 497

(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 August 23, 2011.

* * * * *

7. Add subpart OOOO to part 60 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 well affected facilities?

60.5380 What standards apply to centrifugal compressor 

affected facilities?

60.5385 What standards apply to reciprocating compressor 

affected facilities?

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 

equipment leaks from 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?
Page 205 of 497

60.5408 What is an optional procedure for measuring hydrogen 

sulfide in acid gas—Tutwiler Procedure?

60.5410 How do I demonstrate initial compliance with the 

standards for my gas well 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?

60.5411 What requirements must I meet for closed vent systems 

routing emissions from storage vessels or centrifugal 

compressor wet seal fluid degassing systems?

60.5412 What requirements must I meet for control devices used 

to demonstrate compliance at my storage vessel or 

centrifugal compressor affected facility?

60.5413 What are the performance testing procedures for 

control devices used to demonstrate compliance at my 

storage vessel or centrifugal compressor affected 

facility?

60.5415 How do I demonstrate continuous compliance with the 

standards for my gas well 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?

60.5416 What are the initial and continuous cover and closed 

vent system inspection and monitoring requirements for 

my storage vessel or centrifugal compressor affected 

facility?

60.5417 What are the continuous control device monitoring 

requirements for my storage vessel or centrifugal 

compressor affected facility?

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 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 parts of the General Provisions apply to me?

60.5430 What definitions apply to this subpart?
Page 206 of 497

Table 1 to Subpart OOOO of part 60 – Required Minimum Initial 

SO2 Emission Reduction Efficiency (Zi)

Table 2 to Subpart OOOO of part 60 – Required Minimum SO2 

Emission Reduction Efficiency (Zc)

Table 3 to Subpart OOOO of part 60 – Applicability of General 

Provisions to Subpart OOOO

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 onshore affected 

facilities that commenced construction, modification or 

reconstruction after August 23, 2011. 

§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 August 23, 2011 your affected facility is 

subject to the applicable provisions of this subpart. 

(a) A gas well affected facility, which is a single natural 

gas well. 

(b) A centrifugal compressor affected facility, which is 

defined as a single centrifugal compressor using wet seals that 

is located between the wellhead and the point of custody 

transfer to a natural gas transmission and storage facility, 
Page 207 of 497

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 of original manufacture.

(c) A reciprocating compressor affected facility, which is 

defined as a single reciprocating compressor located between the 

wellhead and the point of custody transfer to a natural gas 

transmission and storage facility, except that a reciprocating 

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 reciprocating compressor is considered to 

have commenced construction on the date of original manufacture.

(d) A pneumatic controller affected facility, which is 

defined as a single natural gas driven pneumatic controller that 

vents continuously (bleeds) to the atmosphere located between 

the wellhead and the point of custody transfer to a natural gas 

transmission and storage facility. 

(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.
Page 208 of 497

(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 

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 paragraphs (f)(1) and (f)(2) 

of this section are exempt from this subpart if they are subject 

to and controlled according to subparts VVa, GGG or GGGa of this 

part.

(g) Sweetening units located at onshore natural gas 

processing plants that process natural gas produced from either 

onshore or offshore wells.
Page 209 of 497

(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 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 §§60.5410(g), 60.5415(g), and 

§60.5423 of this subpart.

(h) For the purposes of this subpart, the operations in 

paragraphs (h)(1) through (h)(4) of this section are 

modifications, but do not affect the modification status of 

other equipment, process units, storage vessels, or pneumatic 

controllers located at the well site.

(1) A well completion operation following hydraulic 

fracturing or refracturing at a gas well facility that commenced 

construction, modification, or reconstruction on or before 

August 23, 2011. 
Page 210 of 497

(2) A well completion operation following hydraulic 

fracturing or refracturing at a gas well facility that commenced 

construction, modification, or reconstruction after August 23, 

2011.

(3) A well recompletion operation that occurs after August 

23, 2011 at a fractured or refractured gas well facility.

(4) A refracturing operation that occurs after August 23, 

2011 at a gas well facility.

§60.5370 When must I comply with this subpart?

(a) You must be in compliance with the standards of this 

subpart no later than [INSERT DATE 60 DAYS AFTER DATE OF 

PUBLICATION 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 provisions of 

this subpart.

§60.5375 What standards apply to gas well affected facilities?
Page 211 of 497

If you are the owner or operator of a gas well 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, begun prior to [INSERT DATE TWO YEARS AFTER 

DATE OF PUBLICATION IN THE FEDERAL REGISTER], you must comply 

with the requirements of paragraph (a)(3) of this section unless 

a more stringent state or local emission control requirement is 

applicable. For each well completion operation with hydraulic 

fracturing begun on or after [INSERT DATE TWO YEARS AFTER DATE 

OF PUBLICATION IN THE FEDERAL REGISTER], you must comply with 

the requirements in paragraphs (a)(1) through (a)(3) of this 

section.

(1) For the duration of flowback, route the recovered 

liquids into one or more storage vessels and route the recovered 

gas into a gas gathering line or collection system.

(2) All salable quality gas must be routed to the gas 

gathering line as soon as practicable.

(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, or where high heat emissions from 

flaring may negatively impact tundra, permafrost or waterways. 
Page 212 of 497

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 well 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 well affected facilities as required 

by §60.5410.

 (d) You must demonstrate continuous compliance with the 

standards that apply to gas well affected facilities as required 

by §60.5415.

 (e) You must perform the required notification, 

recordkeeping, and reporting as required by §60.5420.

(f)(1) For each well completion operation with hydraulic 

fracturing at a gas well affected facility meeting the criteria 

for a wildcat or delineation well, you must comply with the 

requirements of paragraphs (a)(3) and (b)-(e) of this section. 

(2) For each well completion operation with hydraulic 

fracturing at a gas well affected facility meeting the criteria 

for a low pressure non-wildcat or low pressure non-delineation 

well, you must comply with the requirements of paragraphs (a)(3)

and (b)-(e) of this section.
Page 213 of 497

(3) You must also maintain records specified in 

§60.5420(c)(1)(iii) for wildcat or delineation wells and low 

pressure 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)(1) You must reduce VOC emissions from each centrifugal 

compressor wet seal fluid degassing system by 95 percent or 

greater.

(2) If you use a control device to reduce emissions, you 

must equip the wet seal fluid degassing system with a cover that 

is connected through a closed vent system that meets the 

requirements of §60.5411 to a control device that meets the 

conditions specified in §60.5412

(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. 
Page 214 of 497

§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 compressor 

affected facility.

(a) You must replace the reciprocating compressor rod 

packing according to either paragraph (a)(1) or (a)(2) of this 

section.

(1) 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 [INSERT DATE 60 DAYS AFTER DATE OF 

PUBLICATION IN THE FEDERAL REGISTER], or the date of the 

previous reciprocating compressor rod packing replacement, 

whichever is later.

(2) Prior to 36 months from the date of the most recent rod 

packing replacement, or 36 months from the date of installation 

for a new reciprocating compressor for which the rod packing has 

not yet been replaced.

(b) You must demonstrate initial compliance with standards 

that apply to reciprocating compressor affected facilities as 

required by §60.5410.
Page 215 of 497

(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 

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 pneumatic 

controller affected facility with a bleed rate greater than 6 

standard cubic feet per hour is required based on factors such 

as response time, safety and actuation. 

(b)(1) Each new, reconstructed or modified pneumatic 

controller affected facility installed after August 23, 2011, at 

a natural gas processing plant (as defined in §60.5430 must have 

a bleed rate of zero. 

(2) Each new, reconstructed or modified pneumatic 

controller installed after August 23, 2011, at a natural gas 
Page 216 of 497

processing plant must be tagged with the month and year of 

installation, reconstruction or modification, and identification 

information that allows traceability to the records for that 

controlled required in §60.5420(c)(4)(iv).

(c)(1) Each new, reconstructed or modified pneumatic 

controller affected facility installed after August 23, 2011, at 

a location between the wellhead and a natural gas processing 

plant must have a bleed rate less than or equal to 6 standard 

cubic feet per hour.

(2) Each new, reconstructed or modified pneumatic 

controller installed after August 23, 2011, [at a location 

between the wellhead and a natural gas processing plant must be 

tagged with the month and year of installation, reconstruction 

or modification, and identification information that allows 

traceability to the records for that controlled required in 

§60.5420(c)(4)(iii).

(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, 

recordkeeping, and reporting as required by §60.5420, except 
Page 217 of 497

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 this section for each 

storage vessel affected facility with VOC emissions equal to or 

greater than 6 tpy as determined in paragraph (a) of this 

section.

(a)(1) Well sites with no other wells in production. You 

must determine the VOC emission rate for each storage vessel 

affected facility within 30 days after installation, 

modification or reconstruction. For each storage vessel affected 

facility emitting more than 6 tpy VOC you must reduce VOC 

emissions by 95 percent of greater within 60 days after 

installation, modification or reconstruction.

(2) Well sites with one or more wells already in 

production. You must determine the VOC emission rate for each 

storage vessel affected facility upon installation, modification 

or reconstruction. For each storage vessel affected facility 

emitting more than 6 tpy VOC you must reduce VOC emissions by 95 

percent or greater upon installation, modification or 

reconstruction.

(3) If you use a control device to reduce emissions, you 

must equip the storage vessel with a cover that is connected 
Page 218 of 497

through a closed vent system that meets the requirements of 

§60.5411 to a control device that meets the conditions specified 

in §60.5412. 

(4) If you use a vapor recovery device to reduce emissions, 

you must meet the requirements of §60.5411. 

(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 60, subpart Kb, or 40 CFR 

part 63, subparts G, CC, HH, WW, or HHH.

(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.
Page 219 of 497

 (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 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 
Page 220 of 497

field gas before the extraction step in the process. For 

purposes of determining the percent VOC content of the process 

fluid that is 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 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 
Page 221 of 497

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 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.
Page 222 of 497

 (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 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.
Page 223 of 497

 (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 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 
Page 224 of 497

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 §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))
Page 225 of 497

 = 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 (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:
Page 226 of 497

(1) You must compute the emission reduction efficiency (R) 

achieved by the sulfur recovery technology for each run using 

the following equation:

(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 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 
Page 227 of 497

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 crosssectional 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 reductiontype 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 the oxygen 

content of the effluent gas is greater than 1.0 percent by 
Page 228 of 497

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 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, 
Page 229 of 497

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 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.
Page 230 of 497

(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 §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 
Page 231 of 497

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 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. 
Page 232 of 497

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.

(4) 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 
Page 233 of 497

§60.5405(b) will be between 30 and 70 percent of the measurement 

range of the 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 calculate each 1-hour average. 

You must use a minimum of 18 1-hour averages to compute each 24-

hour average.
Page 234 of 497

(e) In lieu of complying with paragraphs (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 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.
Page 235 of 497

§60.5408 What is an optional procedure for measuring hydrogen 

sulfide in acid gas—Tutwiler Procedure? 1

(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 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 

 

1 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 II-I-67).
Page 236 of 497

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). 

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.
Page 237 of 497

(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 starchiodine end point is much less distinct, and a blank 

determination of end point, with H2S-free gas or air, is 

required.
Page 238 of 497

Figure 1. Tutwiler burette (lettered items mentioned in text).

§60.5410 How do I demonstrate initial compliance with the 

standards for my gas well affected facility, my centrifugal 

compressor affected facility, my reciprocating compressor 
Page 239 of 497

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 [INSERT DATE OF PUBLICATION 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 well

affected facility if you have complied with paragraphs (a)(1) 

through (a)(4) of this section.

(1) You have notified the Administrator by the first of 

each month of the anticipated well completion operations during 

that month, 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 (NAD) of 

1983.

(2) You have notified the Administrator by email no later 

than four days prior to each well completion operation the 

actual date of the well completion operation.
Page 240 of 497

(3) 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.

(4) You have submitted the initial annual report for your 

well affected facility as required in §60.5420(b).

(b)(1) You have demonstrated initial compliance with 

standards for your centrifugal compressor affected facility if 

you have reduced VOC emissions from each centrifugal compressor 

wet seal fluid degassing system by 95 percent or greater as 

required by §60.5380.

(2) If you use a control device to reduce emissions, you 

have equipped the wet seal fluid degassing system with a cover 

that is connected through a closed vent system that meets the 

requirements of §60.5411 to a control device that meets the 

conditions specified in §60.5412.

(3) You have conducted an initial performance test as 

required in §60.5413 within 180 days after initial startup or by 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], whichever 

is later, and have conducted the compliance demonstration in 

§60.5415(e).

(4) You have conducted the initial inspections required in 

§60.5416.

(5) You have installed and operated continuous parameter 

monitoring systems in accordance with §60.5417.
Page 241 of 497

(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 or 

tracked the number of months since the last rod packing 

replacement. 

(2) You have included the cumulative number of hours of 

operation for your reciprocating compressor affected facility 

during the initial compliance period or the number of months 

since the last rod packing replacement in your initial annual 

report required in §60.5420(b).

(d) You have achieved initial compliance with emission 

standards for your pneumatic controller affected facility if you 

comply with the requirements specified in paragraphs (d)(1) 

through (d)(5) of this section.

(1) You have demonstrated, to the Administrator’s 

satisfaction, the use of a pneumatic controller affected 

facility with a bleed rate greater than 6 standard cubic feet of 

gas per hour is required 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. 
Page 242 of 497

(3) You own or operate a pneumatic controller affected 

facility located between the wellhead and a natural gas 

processing plant and the manufacturer’s design specifications 

indicate that the controller emits less than or equal to 6 

standard cubic feet of gas per hour.

(4) You have tagged each new, reconstructed or modified 

pneumatic controller according to the requirements of 

§60.5390(c)(2).

(5) You have included the information in paragraph (d)(1) 

of this section and a listing of the pneumatic controller 

affected facilities specified in paragraphs (d)(2) and (d)(3) of 

this section in the initial annual report submitted for your 

pneumatic controller affected facilities installed during the 

period covered by the annual report 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 have 

complied with paragraphs (e)(1) through (e)(6) of this section.

(1) You have determined the VOC emission rate within 30 

days after installation, modification or reconstruction.

(2) You have determined the VOC emission rate for storage 

vessels at well sites one or more wells already in production 

upon installation, modification or reconstruction.
Page 243 of 497

(3) For storage vessel affected facilities emitting more 

than 6 tpy VOC, you have reduced VOC emissions by 95 percent or 

greaer.

(4) If you use a control device to reduce emissions, you 

have equipped the storage vessel with a cover that is connected 

through a closed vent system that meets the requirements of 

§60.5411 to a control device that meets the conditions specified 

in §§60.5412.

(5) You have conducted an initial performance test as 

required in §60.5413 within 180 days after initial startup or by 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], whichever 

is later, and have conducted the compliance demonstration in 

§60.5415(e).

(6) You have conducted the initial inspections required in 

§60.5416.

(7) You have installed and operated continuous parameter 

monitoring systems in accordance with §60.5417.

(8) You have submitted the information in paragraphs (e)(1) 

through (e)(7) of this section in the initial annual report for 

your storage vessel affected facilities installed, modified or 

reconstructed during the period covered by the annual report as 

required in §60.5420(b). 

(f) For affected facilities at onshore natural gas 

processing plants, initial compliance with the VOC requirements 
Page 244 of 497

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 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) of this section in the initial annual report submitted 

for your sweetening unit affected facilities at onshore natural 

gas processing plants. 
Page 245 of 497

§60.5411 What requirements must I meet for closed vent systems 

routing materials from storage vessels and centrifugal 

compressor wet seal degassing systems?

You must meet the applicable requirements of this section 

for each cover and closed vent system used to demonstrate 

initial compliance with the emission standards for your storage 

vessel or centrifugal compressor affected facility.

(a) Closed vent system requirements. (1) You must design 

the closed vent system to route all gases, vapors, and fumes 

emitted from the material in the storage tank or wet seal fluid 

degassing system to a control device that meets the requirements 

specified in §60.5412.

(2) You must design and operate the closed vent system with 

no detectable emissions.

(3) You must meet the requirements specified in paragraphs 

(a)(3)(i) and (a)(3)(ii) of this section if the closed vent 

system contains one or more bypass devices that could be used to 

divert all or a portion of the gases, vapors, or fumes from 

entering the control device.

(i) Except as provided in paragraph (a)(3)(ii) of this 

section, you must comply with either paragraph (a)(3)(i)(A) or 

(a)(3)(i)(B) of this section for each bypass device.

(A) You must properly install, calibrate, maintain, and 

operate a flow indicator at the inlet to the bypass device that 
Page 246 of 497

could divert the stream away from the control device to the 

atmosphere that is capable of taking periodic readings and 

sounding an alarm when the bypass device is open such that the 

stream is being, or could be, diverted away from the control 

device to the atmosphere.

(B) You must secure the bypass device valve installed at 

the inlet to the bypass device in the non-diverting position 

using a car-seal or a lock-and-key type configuration.

(ii) Low leg drains, high point bleeds, analyzer vents, 

open-ended valves or lines, and safety devices are not subject 

to the requirements of paragraph (a)(3)(i) of this section.

(b) Cover requirements. (1) The cover and all openings on 

the cover (e.g., access hatches, sampling ports, and gauge 

wells) shall be designed to form a continuous barrier over the 

entire surface area of the liquid in the storage vessel or wet 

seal fluid degassing system.

(2) Each cover opening shall be secured in a closed, sealed 

position (e.g., covered by a gasketed lid or cap) whenever 

material is in the unit on which the cover is installed except 

during those times when it is necessary to use an opening as 

follows:

(i) To add material to, or remove material from the unit 

(this includes openings necessary to equalize or balance the 
Page 247 of 497

internal pressure of the unit following changes in the level of 

the material in the unit);

(ii) To inspect or sample the material in the unit;

(iii) To inspect, maintain, repair, or replace equipment 

located inside the unit; or

(iv) To vent liquids, gases, or fumes from the unit through 

a closed-vent system to a control device designed and operated 

in accordance with the requirements of paragraph (a) of this 

section.

§60.5412 What requirements must I meet for control devices used 

to demonstrate compliance at my storage vessel or centrifugal 

compressor affected facility?

You must meet the applicable requirements of this section 

for each control device used to demonstrate initial compliance 

with the emission standards for your storage vessel or 

centrifugal compressor affected facility. 

(a) You must use one of the control devices specified in 

paragraphs (a)(1) through (a)(3) of this section and comply with 

the emissions reduction performance requirements for the 

selected control device to reduce VOC emissions in accordance 

with the standards of this subpart. You must demonstrate that 

the control device achieves the performance requirements using 

the performance test methods and procedures specified in 

§60.5413.
Page 248 of 497

(1) You must design and operate an enclosed combustion 

device (e.g., thermal vapor incinerator, catalytic vapor 

incinerator, boiler, or process heater) in accordance with one 

of the performance requirements specified in paragraphs 

(a)(1)(i) through (a)(1)(iv) of this section.

(i) You must reduce the mass content of VOC in the gases 

vented to the device by 95.0 percent by weight or greater as 

determined in accordance with the requirements of §60.5413.

(ii) You must reduce the concentration of TOC in the 

exhaust gases at the outlet to the device to a level equal to or 

less than 20 parts per million by volume on a dry basis 

corrected to 3 percent oxygen as determined in accordance with 

the requirements of §60.5413.

(iii) You must operate at a minimum temperature of 760°C 

for a control device that can demonstrate a uniform combustion 

zone temperature during the performance test conducted under 

§60.5413.

(iv) If a boiler or process heater is used as the control 

device, then you must introduce the vent stream into the flame 

zone of the boiler or process heater.

(2) You must design and operate a vapor recovery device 

(e.g., carbon adsorption system or condenser) or other nondestructive control device to reduce the mass content of VOC in 

the gases vented to the device by 95.0 percent by weight or 
Page 249 of 497

greater as determined in accordance with the requirements of 

§60.5413.

(3) You must design and operate a flare, as defined in 

§60.5430, in accordance with the requirements of §60.18(b).

(b) You must operate each control device in accordance with 

the requirements specified in paragraphs (b)(1) and (b)(2) of 

this section.

(1) You must operate each control device used to comply 

with this subpart at all times when gases, vapors, and fumes are 

vented from the storage vessel or wet seal fluid degassing 

system affected facility through the closed vent system to the 

control device, as required under §60.5395. You may vent more 

than one unit to a control device used to comply with this 

subpart.

(2) For each control device monitored in accordance with 

the requirements of §60.5417, you must demonstrate compliance 

according to the requirements of §60.5415(e), as applicable.

(c) For each carbon adsorption system used as a control 

device to meet the requirements of paragraph (a) of this 

section, you must manage the carbon in accordance with the 

requirements specified in paragraphs (c)(1) or (c)(2) of this 

section.

(1) Following the initial startup of the control device, 

you must replace all carbon in the control device with fresh 
Page 250 of 497

carbon on a regular, predetermined time interval that is no 

longer than the carbon service life established for the carbon 

adsorption system. You must maintain records identifying the 

schedule for replacement and records of each carbon replacement 

as required in §63.774(b)(7)(ix). You must submit the schedule 

for replacement 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).

(2) You must either regenerate, reactivate, or burn the 

spent carbon removed from the carbon adsorption system in one of 

the units specified in paragraphs (c)(2)(i) through (c)(2)(vii) 

of this section.

(i) Regenerate or reactivate the spent carbon in a thermal 

treatment unit for which you have been issued a final permit 

under 40 CFR part 270 that implements the requirements of 40 CFR 

part 264, subpart X.

(ii) Regenerate or reactivate the spent carbon in a thermal 

treatment unit equipped with and operating air emission controls 

in accordance with this section.

(iii) Regenerate or reactivate the spent carbon in a 

thermal treatment unit equipped with and operating organic air 

emission controls in accordance with an emissions standard for 

VOC under another subpart in 40 CFR part 60 or this part.
Page 251 of 497

(iv) Burn the spent carbon in a hazardous waste incinerator 

for which the owner or operator has been issued a final permit 

under 40 CFR part 270 that implements the requirements of 40 CFR 

part 264, subpart O.

(v) Burn the spent carbon in a hazardous waste incinerator 

which you have designed and operated in accordance with the 

requirements of 40 CFR part 265, subpart O.

(vi) Burn the spent carbon in a boiler or industrial 

furnace for which you have been issued a final permit under 40 

CFR part 270 that implements the requirements of 40 CFR part 

266, subpart H.

(vii) Burn the spent carbon in a boiler or industrial 

furnace that you have designed and operated in accordance with 

the interim status requirements of 40 CFR part 266, subpart H.

§60.5413 What are the performance testing procedures for control 

devices used to demonstrate compliance at my storage vessel or 

centrifugal compressor affected facility?

This section applies to the performance testing of control 

devices used to demonstrate compliance with the emissions 

standards for your storage vessel or centrifugal compressor 

affected facility. You must demonstrate that a control device 

achieves the performance requirements of §60.5412(a) using the 

performance test methods and procedures specified in paragraph 

(b) of this section. For condensers, you may use a design 
Page 252 of 497

analysis as specified in paragraph (c) of this section in lieu 

of complying with paragraph (b) of this section. 

(a) Performance test exemptions. You are exempt from the 

requirements to conduct performance tests and design analyses if 

you use any of the control devices described in paragraphs 

(a)(1) through (7) of this section.

(1) A flare, as defined in §60.5430, that is designed and 

operated in accordance with §60.18(b). You must conduct the 

compliance determination using Method 22 at 40 CFR part 60, 

appendix A-7, to determine visible emissions.

(2) A boiler or process heater with a design heat input 

capacity of 44 megawatts or greater.

(3) A boiler or process heater into which the vent stream 

is introduced with the primary fuel or is used as the primary 

fuel.

(4) A boiler or process heater burning hazardous waste for 

which you have either been issued a final permit under 40 CFR 

part 270 and comply with the requirements of 40 CFR part 266, 

subpart H; or you have certified compliance with the interim 

status requirements of 40 CFR part 266, subpart H.

(5) A hazardous waste incinerator for which you have been 

issued a final permit under 40 CFR part 270 and comply with the 

requirements of 40 CFR part 264, subpart O; or you have 
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certified compliance with the interim status requirements of 40 

CFR part 265, subpart O.

(6) A control device for which a performance test was 

conducted for determining compliance with a regulation 

promulgated by the EPA and the test was conducted using the same 

methods specified in this section and either no process changes 

have been made since the test, or you can demonstrate that the 

results of the performance test, with or without adjustments, 

reliably demonstrate compliance despite process changes.

(7) A control device that can be demonstrated to meet the 

performance requirements of §60.5412(a) through a performance 

test conducted by the manufacturer, as specified in paragraph 

(d) of this section.

(b) Test methods and procedures. You must use the test 

methods and procedures specified in paragraphs (b)(1) through 

(b)(5) of this section, as applicable, for each performance test 

conducted to demonstrate that a control device meets the 

requirements of §60.5412(a). You must conduct the initial and 

periodic performance tests according to the schedule specified 

in paragraph (b)(5) of this section.

(1) You must use Method 1 or 1A at 40 CFR part 60, appendix 

A-1, as appropriate, to select the sampling sites specified in 

paragraphs (b)(1)(i) and (b)(1)(ii) of this section. Any 
Page 254 of 497

references to particulate mentioned in Methods 1 and 1A do not 

apply to this section.

(i) Sampling sites must be located at the inlet of the 

first control device, and at the outlet of the final control 

device, to determine compliance with the control device percent 

reduction requirement specified in §60.5412(a)(1)(i) or (a)(2).

(ii) The sampling site must be located at the outlet of the 

combustion device to determine compliance with the enclosed 

combustion device total TOC concentration limit specified in 

§60.5412(a)(1)(ii).

(2) You must determine the gas volumetric flowrate using 

Method 2, 2A, 2C, or 2D at 40 CFR part 60, appendix A-2, as 

appropriate.

(3) To determine compliance with the control device percent 

reduction performance requirement in §60.5412(a)(1)(i) or 

(a)(2), you must use Method 25A at 40 CFR part 60, appendix A-7.

You must use the procedures in paragraphs (b)(3)(i) through 

(b)(3)(iv) of this section to calculate percent reduction 

efficiency.

(i) For each run, you must take either an integrated sample 

or a minimum of four grab samples per hour. If grab sampling is 

used, then the samples must be taken at approximately equal 

intervals in time, such as 15-minute intervals during the run.
Page 255 of 497

(ii) You must compute the mass rate of TOC (minus methane 

and ethane) using the equations and procedures specified in 

paragraphs (b)(3)(ii)(A) and (b)(3)(ii)(B) of this section. 

(A) You must use the following equations:

Where:

Ei, Eo = Mass rate of TOC (minus methane and ethane) at the 

inlet and outlet of the control device, respectively, dry basis, 

kilogram per hour.

K2 = 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) is 

20°C.

Cij, Coj = Concentration of sample component j of the gas 

stream at the inlet and outlet of the control device, 

respectively, dry basis, parts per million by volume.

Mij, Moj = Molecular weight of sample component j of the gas 

stream at the inlet and outlet of the control device, 

respectively, gram/gram-mole.

Qi, Qo = Flowrate of gas stream at the inlet and outlet of 

the control device, respectively, dry standard cubic meter per 

minute.

n = Number of components in sample.

(B) When calculating the TOC mass rate, you must sum all 

organic compounds (minus methane and ethane) measured by Method 

25A at 40 CFR part 60, appendix A-7 using Equations [insert 

numbers here] in of this section.
Page 256 of 497

(iii) You must calculate the percent reduction in TOC (minus 

methane and ethane) as follows:

Where:

Rcd = Control efficiency of control device, percent.

Ei = Mass rate of TOC (minus methane and ethane) at the 

inlet to the control device as calculated under paragraph 

(b)(3)(ii) of this section, kilograms TOC per hour or kilograms 

HAP per hour.

Eo = Mass rate of TOC (minus methane and ethane) at the 

outlet of the control device, as calculated under paragraph 

(b)(3)(ii) of this section, kilograms TOC per hour per hour.

(iv) If the vent stream entering a boiler or process heater 

with a design capacity less than 44 megawatts is introduced with 

the combustion air or as a secondary fuel, you must determine 

the weight-percent reduction of total TOC (minus methane and 

ethane) across the device by comparing the TOC (minus methane 

and ethane) in all combusted vent streams and primary and 

secondary fuels with the TOC (minus methane and ethane) exiting 

the device, respectively.

(4) You must use Method 25A at 40 CFR part 60, appendix A-7 

to measure TOC (minus methane and ethane) to determine 

compliance with the enclosed combustion device total VOC 

concentration limit specified in §60.5412(a)(1)(ii). You must 

calculate parts per million by volume concentration and correct 

to 3 percent oxygen, using the procedures in paragraphs 

(b)(4)(i) through (b)(4)(iii) of this section. 
Page 257 of 497

(i) For each run, you must take either an integrated sample 

or a minimum of four grab samples per hour. If grab sampling is 

used, then the samples must be taken at approximately equal 

intervals in time, such as 15-minute intervals during the run.

(ii) You must calculate the TOC concentration for each run as 

follows:

Where:

CTOC = Concentration of total organic compounds minus methane 

and ethane, dry basis, parts per million by volume.

Cji = Concentration of sample component j of sample i, dry 

basis, parts per million by volume.

n = Number of components in the sample.

x = Number of samples in the sample run.

(iii) You must correct the TOC concentration to 3 percent 

oxygen as specified in paragraphs (b)(4)(iii)(A) and 

(b)(4)(iii)(B) of this section.

(A) You must use the emission rate correction factor for 

excess air, integrated sampling and analysis procedures of 

Method 3A or 3B at 40 CFR part 60, appendix A to determine the 

oxygen concentration. The samples must be taken during the same 

time that the samples are taken for determining TOC 

concentration.

(B) You must correct the TOC concentration for percent 

oxygen as follows:
Page 258 of 497

Where:

Cc = TOC concentration corrected to 3 percent oxygen, dry 

basis, parts per million by volume.

Cm = TOC concentration, dry basis, parts per million by 

volume.

%O2d = Concentration of oxygen, dry basis, percent by volume.

(5) You must conduct performance tests according to the 

schedule specified in paragraphs (b)(5)(i) and (b)(5)(ii) of 

this section.

(i) You must conduct an initial performance test 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 must be conducted [INSERT THE DATE NO 

LATER THAN 3 YEARS AFTER DATE OF PUBLICATION OF THE FINAL RULE 

IN THE FEDERAL REGISTER]. If you choose to replace an existing 

combustion control device at an existing major source with a 

control device whose model is tested under paragraph (d) of this 

section, then the newly installed device must comply with all 

provisions of this subpart no later than [INSERT THE DATE 3 

YEARS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL 

REGISTER]. You must submit the performance test results in the 
Page 259 of 497

Notification of Compliance Status Report as required in 

§63.775(d)(1)(ii).

(ii) You must conduct periodic performance tests for all 

control devices required to conduct initial performance tests 

except as specified in paragraphs (b)(5)(ii)(A) and 

(b)(5)(ii)(B) of this section. You must conduct the first 

periodic performance test no later than 60 months after the 

initial performance test required in paragraph (b)(5)(i) of this 

section. You must conduct subsequent periodic performance tests 

at intervals no longer than 60 months following the previous 

periodic performance test or whenever you desire to establish a 

new operating limit. You must submit the periodic performance 

test results in the next Periodic Report as specified in 

§63.775(e)(2)(xi). Combustion control devices meeting the 

criteria in either paragraph (b)(5)(ii)(A) or (b)(5)(ii)(B) of 

this section are not required to conduct periodic performance 

tests.

(A) A control device whose model is tested under, and meets 

the criteria of paragraph (d) of this section.

(B) A combustion control device tested under paragraph (b) 

of this section that meets the outlet TOC performance level 

specified in §60.5412(a)(1)(ii) and that establishes a 

correlation between firebox or combustion chamber temperature 

and the TOC performance level.
Page 260 of 497

(c) Condenser design analysis. For a condenser design 

analysis conducted to meet the requirements of §60.5412(a), you 

must meet the requirements specified in paragraphs (c)(1) and 

(c)(2) of this section. You must submit documentation of the 

design analysis as a part of the Notification of Compliance 

Status Report as required in §63.775(d)(1)(i).

(1) The condenser design analysis must include an analysis 

of the vent stream composition, constituent concentrations, 

flowrate, relative humidity, and temperature, and must 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 .

(2) If you and the Administrator do not agree on a 

demonstration of control device performance using a design 

analysis, then you must perform a performance test in accordance 

with the requirements of paragraph (b) of this section to 

resolve the disagreement. The Administrator may choose to have 

an authorized representative observe the performance test.

(d) Performance testing for combustion control devices -

manufacturers’ performance test. The manufacturer must 

demonstrate that a specific model of combustion control device 

achieves the performance requirements in paragraph (d)(1) of 

this section by conducting a performance test as specified in 
Page 261 of 497

paragraphs (d)(2) through (d)(8) of this section. You must 

submit a test report for each combustion control device in 

accordance with the requirements in paragraphs (d)(9) of this 

section.

(1) The manufacturer must meet the performance test 

criteria in paragraphs (d)(1)(i) through (d)(1)(iii) of this 

section.

(i) The control device model tested must meet the emission 

levels in paragraphs (d)(1)(i)(A) through (d)(1)(i)(C) of this 

section.

(A) Method 22 at 40 CFR part 60, appendix A-7, results 

under paragraph (d)(6)(iv) of this section with no indication of 

visible emissions.

(B) Average Method 25A at 40 CFR part 60, appendix A-7, 

results under paragraph (d)(8) of this section equal to or less 

than 10.0 parts per million by volume-wet THC as propane 

corrected to 3.0 percent carbon dioxide, and 

(C) Average carbon monoxide emissions determined under 

paragraph (d)(6)(iii) of this section equal to or less than 10 

parts per million by volume-dry, corrected to 3.0 percent carbon 

dioxide.

(ii) The manufacturer must determine a maximum inlet gas 

flow rate, which must not be exceeded for each control device 
Page 262 of 497

model to achieve the criteria in paragraph (d)(1)(i) of this 

section.

(iii) A control device meeting the emission levels in 

paragraph (d)(1)(i)(A) through (d)(1)(i)(C) of this section must 

demonstrate a destruction efficiency of 95.0 percent for VOC 

regulated under this subpart.

(2) Performance testing must consist of three one-hour (or 

longer) test runs for each of the four firing rate settings in 

paragraphs (d)(2)(i) through (d)(2)(iv) of this section, making 

a total of 12 test runs per test. The manufacturer must use 

propene (propylene) gas for the testing fuel. An independent 

third-party laboratory (not affiliated with the control device 

manufacturer or fuel supplier) must perform all fuel analyses.

(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 up 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 up the firing rate to 70 percent of the maximum 
Page 263 of 497

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 up 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) The manufacturer must test all models employing 

multiple enclosures simultaneously and with all burners 

operational. The manufacturer must report results for each 

enclosure individually and for the average of the emissions from 

all interconnected combustion enclosures/chambers. Control 

device operating data must be collected continuously throughout 

the performance test using an electronic Data Acquisition System 

and strip chart. The manufacturer must submit data with the test 

report in accordance with paragraph (d)(9) of this section.

(4) The manufacturer must conduct inlet testing as 

specified in paragraphs (d)(4)(i) through (d)(4)(iii) of this 

section.
Page 264 of 497

(i) The fuel flow metering system must be located in 

accordance with Method 2A at 40 CFR part 60, appendix A-1, (or 

other approved procedure) to measure fuel flow rate at the 

control device inlet location. You must position the fitting for 

filling fuel sample containers a minimum of eight pipe diameters 

upstream of any inlet fuel flow monitoring meter.

(ii) The manufacturer must determine the inlet flow rate 

using Method 2A at 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) The manufacturer must conduct inlet fuel sampling in 

accordance with the criteria in paragraph (d)(5) of this 

section.

(5) The manufacturer must conduct inlet fuel sampling as 

specified in paragraphs (d)(5)(i) and (d)(5)(ii) of this 

section.

(i) At the inlet fuel sampling location, the manufacturer 

must 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 must be 

conducted as specified in paragraphs (d)(5)(i)(A) through 

(d)(5)(i)(C) of this section. 
Page 265 of 497

(A) Open the canister sampling valve at the beginning of 

the total hydrocarbon test, and close the canister at the end of 

the total hydrocarbon test.

(B) Fill one canister for each total hydrocarbon test run.

(C) Label the canisters individually and record on a chain 

of custody form.

(ii) The manufacturer must analyze each fuel sample using 

the methods in paragraphs (d)(5)(ii)(A) through (d)(5)(ii)(D) of 

this section. You must include the results in the test report in 

paragraph (d)(9) of this section.

(A) Hydrocarbon compounds containing between one and five 

atoms of carbon plus benzene using ASTM D1945-03.

(B) Hydrogen (H2), carbon monoxide (CO), carbon dioxide 

(CO2), nitrogen (N2), oxygen (O2) using ASTM D1945-03.

(C) Carbonyl sulfide, carbon disulfide plus mercaptans 

using ASTM D5504.

(D) Higher heating value using ASTM D3588-98 or ASTM D4891-

89.

(6) The manufacturer must conduct outlet testing in 

accordance with the criteria in paragraphs (d)(6)(i) through 

(d)(6)(iv) and (d)(7) of this section.

(i) The manufacturer must sample and measure flowrate in 

accordance with the following:
Page 266 of 497

(A) The manufacturer must position the outlet sampling 

location a minimum of four 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 must 

be used. 

(B) The manufacturer must measure flow rate using Method 1 

at 40 CFR part 60, appendix A-1 for determining flow measurement 

traverse point location, and Method 2 at 40 CFR part 60, 

appendix A-1 for measuring 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 must be used to obtain an accurate flow 

profile.

(ii) The manufacturer must determine molecular weight as 

specified in paragraph (d)(7) of this section. 

(iii) The manufacturer must determine carbon monoxide using 

Method 10 at 40 CFR part 60, appendix A-4. The manufacturer must 

run the test at the same time and with the sample points used 

for the Method 25A at 40 CFR part 60, appendix A-7, testing. An 

instrument range of 0-10 per million by volume-dry (ppmvd) must 

be used.

(iv) The manufacturer must determine visible emissions 

using Method 22 at 40 CFR part 60, appendix A-7. The test must 
Page 267 of 497

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.

(7) The manufacturer must determine molecular weight as 

specified in paragraphs (d)(7)(i) and (d)(7)(ii) of this 

section.

(i) The manufacturer must collect an integrated bag sample 

during the Method 4 at 40 CFR part 60, appendix A-3, moisture 

test. The manufacturer must analyze the bag sample using a gas 

chromatograph-thermal conductivity detector (GC-TCD) analysis 

meeting the criteria in paragraphs (d)(7)(i)(A) through 

(d)(7)(i)(D) of this section.

(A) Collect the integrated sample throughout the entire 

test, and collect representative volumes from each traverse 

location.

(B) Purge the sampling line with stack gas before opening 

the valve and beginning to fill the bag.

(C) Knead or otherwise vigorously mix the bag contents 

prior to the gas chromatograph analysis.

(D) Modify the gas chromatograph-thermal conductivity 

detector calibration procedure in Method 3C at 40 CFR part 60, 

appendix A-2 by using EPA Alt-045 as follows: For the initial 

calibration, triplicate injections of any single concentration 
Page 268 of 497

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, 

repeat the initial calibration using at least three 

concentration levels.

(ii) The manufacturer must report the molecular weight of 

oxygen, carbon dioxide, methane, and nitrogen and include in the 

test report submitted under §63.775(d)(iii). The manufacturer 

must determine moisture using Method 4 at 40 CFR part 60, 

appendix A-3. Traverse both ports with the Method 4 at 40 CFR 

part 60, appendix A-3, sampling train during each test run. The 

manufacturer must not introduce ambient air into the Method 3C 

at 40 CFR part 60, appendix A-2, integrated bag sample during 

the port change.

(8) The manufacturer must determine total hydrocarbons as 

specified by the criteria in paragraphs (d)(8)(i) through 

(d)(8)(vii) of this section.

(i) Conduct THC sampling using Method 25A at 40 CFR part 

60, appendix A-7, except the option for locating the probe in 

the center 10 percent of the stack is not allowed. The THC probe 

must be traversed to 16.7 percent, 50 percent, and 83.3 percent 

of the stack diameter during the testing.
Page 269 of 497

(ii) A valid test must consist of three Method 25A at 40 

CFR part 60, appendix A-7, 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.

(v) THC measurements must be reported in terms of ppmvw as 

propane.

(vi) THC results must be corrected to 3 percent CO2, as 

measured by Method 3C at 40 CFR part 60, appendix A-2.

(vii) Subtraction of methane/ethane from the THC data is 

not allowed in determining results.

(9) For each combustion control device model tested by the 

manufacturer under this section, you must submit the information 

listed in paragraphs (d)(9)(i) through (d)(9)(vi) of this 

section in the test report required under §63.775(d)(1)(iii).

(i) A full schematic of the control device and dimensions 

of the device components.

(ii) The design net heating value (minimum and maximum) of 

the device.
Page 270 of 497

(iii) The test fuel gas flow range (in both mass and 

volume). Include the minimum and maximum allowable inlet gas 

flow rate.

(iv) The air/stream injection/assist ranges, if used.

(v) The test parameter ranges listed in paragraphs 

(d)(9)(v)(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.
Page 271 of 497

(vi) You must include all calibration quality 

assurance/quality control data, calibration gas values, gas 

cylinder certification, and strip charts annotated with test 

times and calibration values in the test report.

§60.5415 How do I demonstrate continuous compliance with the 

standards for my gas well 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 well affected facility, you must 

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, you 

have demonstrated continuous compliance according to paragraphs 

(b)(1) and (b)(2) of this section.

(1) Continuous compliance is demonstrated if the VOC 

emissions from the wet seal fluid degassing system are reduced 

by 95 percent or greater.

(2) If you use a control device to reduce emissions, you 

must demonstrate continuous compliance according to paragraphs 

(e)(2)(i) through (e)(2)(viii) of this section.
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(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 or 

tracked the number of months since initial startup, or [INSERT 

DATE OF PUBLICATION 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 

or number of months since the previous rod packing replacement 

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 or the number of months since the previous rod 

packing replacement reaches 36 months.

(d) For each pneumatic controller affected facility, 

continuous compliance is demonstrated by maintaining the 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 for which the 

VOC emissions are greater than 6 tpy, you have demonstrated 

continuous compliance according to paragraphs (e)(1) and (e)(2) 

of this section.
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(1) Continuous compliance is demonstrated if the VOC 

emissions from each storage vessel are reduced by 95 percent or 

greater.

(2) If you use a control device to reduce VOC emissions, you 

must demonstrate continuous compliance with the performance 

requirements of §60.5412(a)(2) using the procedure specified in 

paragraphs (e)(2)(i) through (e)(2)(viii) of this section. If 

you use a condenser as the control device to achieve the 

requirements specified in §60.5412(a)(2), you may demonstrate 

compliance according to paragraph (e)(2)(viii) of this section. 

You may switch between compliance with paragraphs (e)(2)(i)

through (e)(2)(vii) of this section and compliance with 

paragraph (e)(2)(viii) of this section only after at least 1 

year of operation in compliance with the selected approach. You 

must provide notification of such a change in the compliance 

method in the next Periodic Report, as required in §60.5420(b), 

following the change.

(i) You must establish a site specific maximum or minimum 

monitoring parameter value (as appropriate) according to the 

requirements of §60.5417(f)(1).

(ii) You must calculate the daily average of the applicable 

monitored parameter in accordance with §60.5417(e) except that 

the inlet gas flow rate to the control device must not be 

averaged.
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(iii) Compliance with the operating parameter limit is 

achieved when the daily average of the monitoring parameter 

value calculated under paragraph (e)(2)(ii) of this section is 

either equal to or greater than the minimum monitoring value or 

equal to or less than the maximum monitoring value established 

under paragraph (e)(2)(i) of this section. When performance 

testing of a combustion control device is conducted by the 

device manufacturer as specified in §60.5413(d), compliance with 

the operating parameter limit is achieved when the inlet gas 

flow rate is equal to or less than the value established under 

§60.5413(d)(1)(ii).

(iv) You must operate the continuous monitoring system 

required in §60.5417 at all times the affected source is 

operating, 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). 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 are not malfunctions. You are 

required to complete monitoring system repairs in response to 
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monitoring system malfunctions and to return the monitoring 

system to operation as expeditiously as practicable.

(v) You may not use data recorded during monitoring system 

malfunctions, repairs associated with monitoring system 

malfunctions, or required monitoring system quality assurance or 

control activities in calculations used to report emissions or 

operating levels. You must use all the data collected during 

all other required data collection periods to assess the 

operation of the control device and associated control system. 

(vi) Failure to collect required data is a deviation of the 

monitoring requirements, 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).

(vii) If you use a combustion control device to meet the 

requirements of §60.5412(a), you must demonstrate compliance by 

installing a device tested under the provisions in §60.5413(d) 

and complying with the criteria in paragraphs (e)(2)(vii)(A)

through (e)(2)(vii)(D) of this section.

(A) The inlet gas flow rate must meet the range specified 

by the manufacturer. You must measure the flow rate as specified 

in §60.5417(d)(1)(viii)(A).
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(B) A pilot flame must be present at all times of 

operation. You must monitor the pilot flame in accordance with 

§60.5417(d)(1)(viii)(B).

(C) You must operate the combustion control device with no 

visible emissions, except for periods not to exceed a total of 5 

minutes during any 2 consecutive hours. You must perform a 

visible emissions test using Method 22 at 40 CFR part 60, 

appendix A-7 monthly. The observation period must be 2 hours and 

must follow Method 22. 

(D) Compliance with the operating parameter limit is 

achieved when the criteria in paragraphs (e)(2)(vii)(D)(1)

through (e)(2)(vii)(D)(6) are met.

(1) The inlet gas flow rate monitored under paragraph 

(e)(2)(vii)(A) of this section is equal to or below the maximum 

established by the manufacturer.

(2) The pilot flame is present at all times; and

(3) During the visible emissions test performed under 

paragraph (e)(2)(vii)(C) 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 must follow the requirements in paragraphs 

(e)(2)(vii)(D)(4) and (e)(2)(vii)(D)(5) of this section.

(4) Following the first failure, you must replace the fuel 

nozzle(s) and burner tubes. 
Page 277 of 497

(5) If, following replacement of the fuel nozzle(s) and 

burner tubes as specified in paragraph (e)(2)(vii)(D)(4) of this 

section, the visible emissions test is not passed in the next 

scheduled test, you must either conduct a performance test as 

specified in §60.5413, or replace the device with another 

control device whose model was tested and meets the requirements 

in §60.5413(d).

(viii) If you use a condenser as the control device to 

achieve the percent reduction performance requirements specified 

in §60.5412(a)(2), you must demonstrate compliance using the 

procedures in paragraphs (e)(2)(viii)(A) through (e)(2)(viii)(E)

of this section.

(A) You must establish a site-specific condenser 

performance curve according to §60.5417(f)(2). 

(B) You must calculate the daily average condenser outlet 

temperature in accordance with §60.5417(e).

(C) You must determine the condenser efficiency for the 

current operating day using the daily average condenser outlet 

temperature calculated under paragraph (e)(2)(viii)(B) of this 

section and the condenser performance curve established under 

paragraph (e)(2)(viii)(A) of this section.

(D) Except as provided in paragraphs (e)(2)(viii)(D)(1) and 

(e)(2)(viii)(D)(2) of this section, at the end of each operating 

day, you must calculate the 365-day average TOC emission 
Page 278 of 497

reduction, as appropriate, from the condenser efficiencies as 

determined in paragraph (e)(2)(viii)(C) of this section for the 

preceding 365 operating days. 

(1) After the compliance dates specified in §63.760(f), if 

you have less than 120 days of data for determining average TOC 

emission reduction, you must calculate the average TOC emission 

reduction for the first 120 days of operation after the 

compliance dates. You have demonstrated compliance with the 

overall 95.0 percent reduction requirement if the 120-day 

average TOC emission reduction is equal to or greater than 90.0 

percent. 

(2) After 120 days and no more than 364 days of operation 

after the compliance dates specified in §63.760(f), you must 

calculate the average TOC emission reduction as the TOC emission 

reduction averaged over the number of days between the current 

day and the applicable compliance date. You have demonstrated 

compliance with the overall 95.0 percent reduction requirement, 

if the average TOC emission reduction is equal to or greater 

than 90.0 percent. 

(E) If you have data for 365 days or more of operation, you 

have demonstrated compliance with the TOC emission reduction 

specified in §60.5412(a)(2) if the average TOC emission 

reduction calculated in paragraph (e)(2)(viii)(D) of this 

section is equal to or greater than 95.0 percent.
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(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 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 §§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 violations of such 

standards that are caused by malfunction, as defined at §60.2. 

Appropriate penalties may be assessed, however, if you fail to 

meet your burden of proving all of the requirements in the 
Page 280 of 497

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 standard, you must timely meet the notification 

requirements in §60.5420(a), and must prove by a preponderance 

of evidence that:

(i) The violation: 

(A) Was 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 

(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 a 

violation occurred. Off-shift and overtime labor were used, to 

the extent practicable to make these repairs; and

(iii) The frequency, amount and duration of the violation

(including any bypass) were minimized to the maximum extent 

practicable; and
Page 281 of 497

(iv) If the violation 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 violation on ambient air quality, the environment and human 

health; and

(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 violation 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, the 

purpose of which is to determine, correct, and eliminate the 

primary causes of the malfunction and the violation resulting 

from the malfunction event at issue. The analysis shall also 

specify, using best monitoring methods and engineering judgment, 

the amount of any emissions that were the result of the 

malfunction. 
Page 282 of 497

(2) Report. The owner or operator seeking to assert an 

affirmative defense shall submit a written report to the 

Administrator in a semiannual report with all necessary 

supporting documentation, that it has met the requirements set 

forth in paragraph (h)(1) of this section.

§60.5416 What are the initial and continuous cover and closed 

vent system inspection and monitoring requirements for my 

storage vessel and centrifugal compressor affected facility?

For each closed vent system or cover at your storage vessel 

or centrifugal compressor affected facility, you must comply 

with the requirements of paragraphs (a) through (g) of this 

section.

(a) Inspections. Except as provided in paragraphs (e) and 

(f) of this section, you must inspect each closed vent system 

according to the procedures and schedule specified in paragraphs 

(a)(1) and (a)(2) of this section, inspect each cover according 

to the procedures and schedule specified in paragraph (a)(3) of 

this section, and inspect each bypass device according to the 

procedures of paragraph (a)(4) of this section.

(1) For each closed vent system joint, seam, or other 

connection that is permanently or semi-permanently sealed (e.g., 

a welded joint between two sections of hard piping or a bolted 

and gasketed ducting flange), you must meet the requirements 
Page 283 of 497

specified in paragraphs (a)(1)(i) and (a)(1)(ii) of this 

section.

(i) Conduct an initial inspection according to the test 

methods and procedures specified in paragraph (b) of this 

section to demonstrate that the closed vent system operates with 

no detectable emissions. You must submit the inspection results 

with the Notification of Compliance Status Report as specified 

in §63.775(d)(1) or (2).

(ii) Conduct annual visual inspections for defects that 

could result in air emissions. Defects include, but are not 

limited to, visible cracks, holes, or gaps in piping; loose 

connections; or broken or missing caps or other closure devices. 

You must monitor a component or connection using the test 

methods and procedures in paragraph (b) of this section to 

demonstrate that it operates with no detectable emissions 

following any time the component is repaired or replaced or the 

connection is unsealed. You must submit the inspection results 

in the Periodic Report as specified in §63.775(e)(2)(iii).

(2) For closed vent system components other than those 

specified in paragraph (a)(1) of this section, you must meet the 

requirements of paragraphs (a)(2)(i) through (a)(2)(iii) of this 

section.

(i) Conduct an initial inspection according to the test 

methods and procedures specified in paragraph (b) of this 
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section to demonstrate that the closed vent system operates with 

no detectable emissions. You must submit the inspection results 

with the Notification of Compliance Status Report as specified 

in §63.775(d)(1) or (2).

(ii) Conduct annual inspections according to the test 

methods and procedures specified in paragraph (b) of this 

section to demonstrate that the components or connections 

operate with no detectable emissions. You must submit the 

inspection results in the Periodic Report as specified in 

§63.775(e)(2)(iii).

(iii) Conduct annual visual inspections for defects that 

could result in air emissions. Defects include, but are not 

limited to, visible cracks, holes, or gaps in ductwork; loose 

connections; or broken or missing caps or other closure devices. 

You must submit the inspection results in the Periodic Report as 

specified in §63.775(e)(2)(iii).

(3) For each cover, you must meet the requirements in 

paragraphs (a)(3)(i) and (a)(3)(ii) of this section.

(i) Conduct visual inspections for defects that could 

result in air emissions. Defects include, but are not limited 

to, visible cracks, holes, or gaps in the cover, or between the 

cover and the separator wall; broken, cracked, or otherwise 

damaged seals or gaskets on closure devices; and broken or 

missing hatches, access covers, caps, or other closure devices. 
Page 285 of 497

In the case where the storage vessel is buried partially or 

entirely underground, you must inspect only those portions of 

the cover that extend to or above the ground surface, and those 

connections that are on such portions of the cover (e.g., fill 

ports, access hatches, gauge wells, etc.) and can be opened to 

the atmosphere.

(ii) You must initially conduct the inspections specified 

in paragraph (a)(3)(i) of this section following the 

installation of the cover. You must submit the inspection 

results with the Notification of Compliance Status Report as 

specified in §63.775(d)(12). Thereafter, you must perform the 

inspection at least once every calendar year, except as provided 

in paragraphs (e) and (f) of this section. You must submit 

annual inspection results in the Periodic Report as specified in 

§63.775(e)(2)(iii).

(4) For each bypass device, except as provided for in 

§63.5411, you must meet the requirements of paragraphs (a)(4)(i) 

or (a)(4)(ii) of this section.

(i) Set the flow indicator to take a reading at least once 

every 15 minutes at the inlet to the bypass device that could 

divert the steam away from the control device to the atmosphere.

(ii) If the bypass device valve installed at the inlet to 

the bypass device is secured in the non-diverting position using 

a car-seal or a lock-and-key type configuration, visually 
Page 286 of 497

inspect the seal or closure mechanism at least once every month 

to verify that the valve is maintained in the non-diverting 

position and the vent stream is not diverted through the bypass 

device.

(b) No detectable emissions test methods and procedures. If 

you are required to conduct an inspection of a closed vent 

system or cover at your storage vessel or centrifugal compressor 

affected facility as specified in paragraphs (a)(1), (a)(2), or 

(a)(3) of this section, you must meet the requirements of 

paragraphs (b)(1) through (b)(8) of this section.

(1) You must conduct the no detectable emissions test 

procedure in accordance with Method 21 at 40 CFR part 60, 

appendix A-7.

(2) The detection instrument must meet the performance 

criteria of Method 21 at 40 CFR part 60, appendix A-7, except 

that the instrument response factor criteria in section 3.1.2(a) 

of Method 21 must be for the average composition of the fluid 

and not for each individual organic compound in the stream.

(3) You must calibrate the detection instrument before use 

on each day of its use by the procedures specified in Method 21 

at 40 CFR part 60, appendix A-7.

(4) Calibration gases must be as specified in paragraphs 

(b)(4)(i) and (b)(4)(ii) of this section.
Page 287 of 497

(i) Zero air (less than 10 parts per million by volume 

hydrocarbon in air).

(ii) A mixture of methane in air at a concentration less 

than 10,000 parts per million by volume.

(5) You may choose to adjust or not adjust the detection 

instrument readings to account for the background organic 

concentration level. If you choose to adjust the instrument 

readings for the background level, you must determine the 

background level value according to the procedures in Method 21 

at 40 CFR part 60, appendix A-7.

(6) Your detection instrument must meet the performance 

criteria specified in paragraphs (b)(6)(i) and (b)(6)(ii) of 

this section.

(i) Except as provided in paragraph (b)(6)(ii) of this 

section, the detection instrument must meet the performance 

criteria of Method 21 at 40 CFR part 60, appendix A-7, except 

the instrument response factor criteria in section 3.1.2(a) of 

Method 21 must be for the average composition of the process 

fluid, not each individual volatile organic compound in the 

stream. For process streams that contain nitrogen, air, or other 

inerts that are not organic hazardous air pollutants or volatile 

organic compounds, you must calculate the average stream 

response factor on an inert-free basis.
Page 288 of 497

(ii) If no instrument is available that will meet the 

performance criteria specified in paragraph (b)(6)(i) of this 

section, you may adjust the instrument readings by multiplying 

by the average response factor of the process fluid, calculated 

on an inert-free basis, as described in paragraph (b)(6)(i) of 

this section.

(7) You must determine if a potential leak interface 

operates with no detectable emissions using the applicable 

procedure specified in paragraph (b)(7)(i) or (b)(7)(ii) of this 

section.

(i) If you choose not to adjust the detection instrument 

readings for the background organic concentration level, then 

you must directly compare the maximum organic concentration 

value measured by the detection instrument to the applicable 

value for the potential leak interface as specified in paragraph 

(b)(8) of this section.

(ii) If you choose to adjust the detection instrument 

readings for the background organic concentration level, you 

must compare the value of the arithmetic difference between the 

maximum organic concentration value measured by the instrument 

and the background organic concentration value as determined in 

paragraph (b)(5) of this section with the applicable value for 

the potential leak interface as specified in paragraph (b)(8) of 

this section.
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(8) A potential leak interface is determined to operate 

with no detectable organic emissions if the organic 

concentration value determined in paragraph (b)(7) of this 

section is less than 500 parts per million by volume.

(c) Repairs. In the event that a leak or defect is 

detected, you must repair the leak or defect as soon as 

practicable according to the requirements of paragraphs (c)(1) 

and (c)(2) of this section, except as provided in paragraph (d) 

of this section.

(1) A first attempt at repair must be made no later than 5 

calendar days after the leak is detected.

(2) Repair must be completed no later than 15 calendar days 

after the leak is detected.

(d) Delay of repair. Delay of repair of a closed vent 

system or cover for which leaks or defects have been detected is 

allowed if the repair is technically infeasible without a 

shutdown, as defined in §60.5430, or if you determine that 

emissions resulting from immediate repair would be greater than 

the fugitive emissions likely to result from delay of repair. 

You must complete repair of such equipment by the end of the 

next shutdown.

(e) Unsafe to inspect requirements. You may designate any 

parts of the closed vent system or cover as unsafe to inspect if 

the requirements in paragraphs (e)(1) and (e)(2) of this section 
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are met. Unsafe to inspect parts are exempt from the inspection 

requirements of paragraphs (a)(1) through (a)(3) of this 

section.

(1) You determine that the equipment is unsafe to inspect 

because inspecting personnel would be exposed to an imminent or 

potential danger as a consequence of complying with paragraphs 

(a)(1), (a)(2), or (a)(3) of this section.

(2) You have a written plan that requires inspection of the 

equipment as frequently as practicable during safe-to-inspect 

times.

(f) Difficult to inspect requirements. You may designate 

any parts of the closed vent system or cover as difficult to 

inspect, if the requirements in paragraphs (f)(1) and (f)(2) of 

this section are met. Difficult to inspect parts are exempt from 

the inspection requirements of paragraphs (a)(1) through (a)(3) 

of this section.:

(1) You determine that the equipment cannot be inspected 

without elevating the inspecting personnel more than 2 meters 

above a support surface.

(2) You have a written plan that requires inspection of the 

equipment at least once every 5 years.

(g) Records. Records shall be maintained as specified in 

§63.774(b)(5) through (8).
Page 291 of 497

§60.5417 What are the continuous control device monitoring 

requirements for my storage vessel or centrifugal compressor 

affected facility?

You must meet the applicable requirements of this section 

for each control device used to demonstrate continuous 

compliance with the emission standards for your storage vessel 

or centrifugal compressor affected facility. 

(a) You must install and operate a continuous parameter 

monitoring system for each control device as specified in 

paragraphs (c) through (j) of this section, except as provided 

for in paragraph (b) of this section. If you install and operate 

a flare in accordance with §60.5412(a)(3), you are exempt from 

the requirements of paragraphs (e) and (f) of this section. 

(b) You are exempt from the monitoring requirements 

specified in paragraphs (c) through (j) of this section for the 

control devices listed in paragraphs (b)(1) and (b)(2) of this

section.

(1) A boiler or process heater in which all vent streams 

are introduced with the primary fuel or is used as the primary 

fuel.

(2) A boiler or process heater with a design heat input 

capacity equal to or greater than 44 megawatts.

(c) You must design and operate the continuous monitoring 

system so that a determination can be made on whether the 
Page 292 of 497

control device is achieving the applicable performance 

requirements of §60.5412. For each continuous parameter 

monitoring system, you must meet the specifications and 

requirements in paragraphs (c)(1) through (c)(4) of this 

section.

(1) Each continuous parameter monitoring system must 

measure data values at least once every hour and record the 

parameters in paragraphs (c)(1)(i) or (c)(1)(ii) of this 

section.

(i) Each measured data value.

(ii) Each block average value for each 1-hour period or 

shorter periods calculated from all measured data values during 

each period. If values are measured more frequently than once 

per minute, a single value for each minute may be used to 

calculate the hourly (or shorter period) block average instead 

of all measured values.

(2) You must prepare a site-specific monitoring plan that 

addresses the monitoring system design, data collection, and the 

quality assurance and quality control elements outlined in 

paragraphs (c)(2)(i) through (c)(2)(v) of this section and in 

§63.8(d). You must install, calibrate, operate, and maintain 

each continuous parameter monitoring system in accordance with 

the procedures in your approved site-specific monitoring plan. 

Using the process described in §63.8(f)(4), you may request 
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approval of monitoring system quality assurance and quality 

control procedures alternative to those specified in paragraphs 

(c)(2)(i) through (v) of this section in your site-specific 

monitoring plan.

(i) The performance criteria and design specifications for 

the monitoring system equipment, including the sample interface, 

detector signal analyzer, and data acquisition and calculations.

(ii) Sampling interface (e.g., thermocouple) location such 

that the monitoring system will provide representative 

measurements. 

(iii) Equipment performance checks, system accuracy audits, 

or other audit procedures.

(iv) Ongoing operation and maintenance procedures in 

accordance with provisions in §63.8(c)(1) and (c)(3).

(v) Ongoing reporting and recordkeeping procedures in 

accordance with provisions in §63.10(c), (e)(1), and (e)(2)(i).

(3) You must conduct the continuous parameter monitoring 

system equipment performance checks, system accuracy audits, or 

other audit procedures specified in the site-specific monitoring 

plan at least once every 12 months.

(4) You must conduct a performance evaluation of each 

continuous parameter monitoring system in accordance with the 

site-specific monitoring plan.
Page 294 of 497

(d) You must install, calibrate, operate, and maintain a 

device equipped with a continuous recorder to measure the values 

of operating parameters appropriate for the control device as 

specified in either paragraph (d)(1), (d)(2), or (d)(3) of this 

section.

(1) A continuous monitoring system that measures the 

operating parameters in paragraphs (d)(1)(i) through 

(d)(1)(viii) of this section, as applicable.

(i) For a thermal vapor incinerator that demonstrates 

during the performance test conducted under §60.5413 that 

combustion zone temperature is an accurate indicator of 

performance, a temperature monitoring device equipped with a 

continuous recorder. The monitoring device must have a minimum 

accuracy of ±1 percent of the temperature being monitored in °C, 

or ±2.5 °C, whichever value is greater. You must install the 

temperature sensor at a location representative of the 

combustion zone temperature.

(ii) For a catalytic vapor incinerator, a temperature 

monitoring device equipped with a continuous recorder. The 

device must be capable of monitoring temperature at two 

locations and have a minimum accuracy of ±1 percent of the 

temperature being monitored in °C, or ±2.5 °C, whichever value 

is greater. You must install one temperature sensor in the vent 

stream at the nearest feasible point to the catalyst bed inlet, 
Page 295 of 497

and you must install a second temperature sensor in the vent 

stream at the nearest feasible point to the catalyst bed outlet.

(iii) For a flare, a heat sensing monitoring device 

equipped with a continuous recorder that indicates the 

continuous ignition of the pilot flame.

(iv) For a boiler or process heater, a temperature 

monitoring device equipped with a continuous recorder. The 

temperature monitoring device must have a minimum accuracy of ±1 

percent of the temperature being monitored in °C, or ±2.5 °C, 

whichever value is greater. You must install the temperature 

sensor at a location representative of the combustion zone 

temperature.

(v) For a condenser, a temperature monitoring device 

equipped with a continuous recorder. The temperature monitoring 

device must have a minimum accuracy of ±1 percent of the 

temperature being monitored in °C, or ±2.8 °C, whichever value 

is greater. You must install the temperature sensor at a 

location in the exhaust vent stream from the condenser.

(vi) For a regenerative-type carbon adsorption system, a 

continuous monitoring system that meets the specifications in 

paragraphs (d)(1)(vi)(A) and (d)(1)(vi)(B) of this section. 

(A) The continuous parameter monitoring system must measure 

and record the average total regeneration stream mass flow or 

volumetric flow during each carbon bed regeneration cycle. The 
Page 296 of 497

flow sensor must have a measurement sensitivity of 5 percent of 

the flow rate or 10 cubic feet per minute, whichever is greater. 

You must check the mechanical connections for leakage at least 

every month, and you must perform a visual inspection at least 

every 3 months of all components of the flow continuous 

parameter monitoring system for physical and operational 

integrity and all electrical connections for oxidation and 

galvanic corrosion if your flow continuous parameter monitoring 

system is not equipped with a redundant flow sensor; and

(B) The continuous parameter monitoring system must measure 

and record the average carbon bed temperature for the duration 

of the carbon bed steaming cycle and measure the actual carbon 

bed temperature after regeneration and within 15 minutes of 

completing the cooling cycle. The temperature monitoring device 

must have a minimum accuracy of ±1 percent of the temperature 

being monitored in °C, or ±2.5 °C, whichever value is greater.

(vii) For a nonregenerative-type carbon adsorption system, 

you must monitor the design carbon replacement interval 

established using a performance test performed as specified in 

§60.5413(b). The design carbon replacement interval must be 

based on the total carbon working capacity of the control device 

and source operating schedule.

(viii) For a combustion control device whose model is

tested under §60.5413(d), a continuous monitoring system meeting 
Page 297 of 497

the requirements of paragraphs (d)(1)(viii)(A) and 

(d)(1)(viii)(B) of this section.

(A) The continuous monitoring system must measure gas flow 

rate at the inlet to the control device. The monitoring 

instrument must have an accuracy of ±2 percent or better.

(B) A heat sensing monitoring device equipped with a 

continuous recorder that indicates the continuous ignition of 

the pilot flame.

(2) A continuous monitoring system that measures the 

concentration level of organic compounds in the exhaust vent 

stream from the control device using an organic monitoring 

device equipped with a continuous recorder. The monitor must 

meet the requirements of Performance Specification 8 or 9 of 40 

CFR part 60, appendix B. You must install, calibrate, and 

maintain the monitor according to the manufacturer's 

specifications.

(3) A continuous monitoring system that measures operating 

parameters other than those specified in paragraph (d)(1) or 

(d)(2) of this section, upon approval of the Administrator as 

specified in §63.8(f)(1) through (5).

(e) You must calculate the daily average value for each 

monitored operating parameter for each operating day, using the 

data recorded by the monitoring system, except for inlet gas 

flow rate. If the emissions unit operation is continuous, the 
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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.

(f) For each operating parameter monitor installed in 

accordance with the requirements of paragraph (d) of this 

section, you must comply with paragraph (f)(1) of this section 

for all control devices. When condensers are installed, you must 

also comply with paragraph (f)(2) of this section.

(1) You must 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 §60.5412(a). You must establish each 

minimum or maximum operating parameter value as specified in 

paragraphs (f)(1)(i) through (f)(1)(iii) of this section.

(i) If you conduct performance tests in accordance with the 

requirements of §60.5413(b) to demonstrate that the control 

device achieves the applicable performance requirements 

specified in §60.5412(a), then you must establish the minimum 

operating parameter value or the maximum operating parameter 

value based on values measured during the performance test and 
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supplemented, as necessary, by a condenser design analysis or 

control device manufacturer recommendations or a combination of 

both.

(ii) If you use a condenser design analysis in accordance 

with the requirements of §60.5413(c) to demonstrate that the 

control device achieves the applicable performance requirements 

specified in §60.5412(a), then you must establish the minimum 

operating parameter value or the maximum operating parameter 

value based on the condenser design analysis and supplemented, 

as necessary, by the condenser manufacturer's recommendations.

(iii) If you operate a control device where the performance 

test requirement was met under §60.5413(d) to demonstrate that 

the control device achieves the applicable performance 

requirements specified in §60.5412(a), then you must establish 

the maximum inlet gas flow rate based on the performance test 

and supplemented, as necessary, by the manufacturer 

recommendations.

(2) If you use a condenser as specified in paragraph 

(d)(1)(v) of this section, you must establish a condenser 

performance curve showing the relationship between condenser 

outlet temperature and condenser control efficiency, according 

to the requirements of paragraphs (f)(2)(i) and (f)(2)(ii) of 

this section .
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(i) If you conduct a performance test in accordance with 

the requirements of §60.5413(b) to demonstrate that the 

condenser achieves the applicable performance requirements in 

§60.5412(a), then the condenser performance curve must 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.

(ii) If you use a control device design analysis in 

accordance with the requirements of §60.5413(c)(1) to 

demonstrate that the condenser achieves the applicable 

performance requirements specified in §60.5412(a), then the 

condenser performance curve must be based on the condenser 

design analysis and supplemented, as necessary, by the control 

device manufacturer's recommendations.

(g) 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 

(g)(1) through (g)(6) of this section being met. If you monitor 

multiple operating parameters for the same control device during 

the same operating day and more than one of these operating 

parameters meets an excursion criterion specified in paragraphs 

(g)(1) through (g)(6) of this section, then a single excursion 

is determined to have occurred for the control device for that 

operating day.
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(1) An excursion occurs when the daily average value of a 

monitored operating parameter is less than the minimum operating 

parameter limit (or, if applicable, greater than the maximum 

operating parameter limit) established in paragraph (f)(1) of 

this section.

(2) If you meet §60.5412(a)(2), an excursion occurs when 

the 365-day average condenser efficiency calculated according to 

the requirements specified in §60.5415(e)(8)(iv) is less than 

95.0 percent. 

(3) If you meet §60.5412(a)(2) and you have less than 365 

days of data, an excursion occurs when the average condenser 

efficiency calculated according to the procedures specified in 

§60.5415(e)(8)(iv)(A) or (B) is less than 90.0 percent. 

(4) An excursion occurs when the monitoring data are not 

available for at least 75 percent of the operating hours in a 

day.

(5) If the closed vent system contains one or more bypass 

devices that could be used to divert all or a portion of the 

gases, vapors, or fumes from entering the control device, an 

excursion occurs when the requirements of paragraphs (g)(5)(i) 

and (g)(5)(ii) of this section are met.

(i) For each bypass line subject to §60.5411(a)(3)(i)(A), 

the flow indicator indicates that flow has been detected and 
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that the stream has been diverted away from the control device 

to the atmosphere.

(ii) For each bypass line subject to §60.5411(a)(3)(i)(B), 

if the seal or closure mechanism has been broken, the bypass 

line valve position has changed, the key for the lock-and-key 

type lock has been checked out, or the car-seal has broken.

(6) For a combustion control device whose model is tested 

under §60.5413(d), an excursion occurs when the conditions of 

paragraphs (g)(6)(i) or (g)(6)(ii) are met.

(i) The inlet gas flow rate exceeds the maximum established 

during the test conducted under §60.5413(d).

(ii) Failure of the monthly visible emissions test 

conducted under §60.5415(e)(7)(iii) occurs. 

(h) For each excursion, you are deemed to have failed to 

have applied control in a manner that achieves the required 

operating parameter limits, except as provided for in paragraph 

(i) of this section. Failure to achieve the required operating 

parameter limits is a violation of this standard.

(i) An excursion is not a violation of the operating 

parameter limit as specified in paragraphs (i)(1) and (i)(2) of 

this section.

(1) An excursion does not count toward the number of 

excused excursions allowed under paragraph (i)(2) of this 

section when the excursion occurs during any one of the periods 
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identified in paragraphs (i)(1)(i) and (i)(1)(ii) of this 

section.

(i) During a malfunction when the affected facility is 

operated during such period in accordance with §63.6(e)(1); or

(ii) During periods of non-operation of the unit or the 

process that is vented to the control device (resulting in 

cessation of VOC emissions to which the monitoring applies).

(2) 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 in accordance 

with §63.775(e) of this subpart.

(j) Nothing in paragraphs (a) through (i) of this section 

is construed to allow or excuse a monitoring parameter excursion 

caused by any activity that violates other applicable provisions 

of this subpart.

§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 that was 

installed, modified, or replaced during the reporting period. 
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(1) If you own or operate a gas well, pneumatic controller

or storage vessel 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 well affected facility, you 

must submit the notifications specified in paragraphs (a)(2)(i) 

and (a)(2)(ii) of this section to the Administrator.

(i) By the first of each month in which you anticipate the 

commencement of one or more well completion operations, you must 

submit a notification to the Administrator listing each 

anticipated well completion operation during that month. The 

notification shall include 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. You may submit the notification in 

writing or in electronic format.

(ii) No earlier than 3 days or later than 2 days prior to 

the commencement of each well completion operation, you must 

send an email notification to the Administrator of the actual 

commencement date of the well completion operation.

(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 and 

performance test reports as specified in paragraph (b)(7) of 
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this section. The initial annual report is due up to 1 year 

after the initial startup date for your affected facility or up 

to 1 year after [INSERT DATE OF PUBLICATION 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. Annual reports 

may coincide with title V reports as long as all the required 

elements of the annual report are included. You may arrange with 

the Administrator a common schedule on which reports required by 

this part may be submitted as long as the schedule does not 

extend the reporting period. 

(1) The general information specified in paragraphs 

(b)(1)(i) through (b)(1)(iv) 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.

(iv) A certification by a responsible official of truth, 

accuracy, and completeness. This certification shall state that, 

based on information and belief formed after reasonable inquiry, 
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the statements and information in the document are true, 

accurate, and complete.

(2) For each gas well 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 well affected facility 

conducted during the reporting period;

(ii) Records of deviations specified in paragraph 

(c)(1)(ii) of this section that occurred during the reporting 

period. 

(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, the 

information specified in paragraphs (b)(3)(i) and (b)(3)(ii) of 

this section.

(i) An identification of each centrifugal compressor 

installed, modified or reconstructed during the reporting 

period.

(ii) Records of deviations specified in paragraph (c)(2) of 

this section that occurred during the reporting period.

(4) For each reciprocating compressor affected facility, 

the information specified in paragraphs (b)(4)(i) through

(b)(4)(iii) of this section.
Page 307 of 497

(i) The cumulative number of hours or operation or the 

number of months since initial startup, [INSERT DATE OF 

PUBLICATION 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 26,000 hours or 36 months from the previous 

rod packing replacement.

(iii) Records of deviations specified in paragraph (c)(3)(iii) 

of this section that occurred during the reporting period.

(5) For each pneumatic controller affected facility, the 

information specified in paragraphs (b)(5)(i) through (b)(5)(v) 

of this section.

(i) An identification of each pneumatic controller 

installed, modified or reconstructed during the reporting 

period, including the identification information specified in 

§60.5390(c)(2).

(ii) If applicable, documentation that the use of pneumatic 

controller affected facilities with a natural gas bleed rate 

greater than 6 standard cubic feet per hour are required and the 

reasons why.
Page 308 of 497

(iii) Records of deviations specified in paragraph 

(c)(4)(v) of this section that occurred during the reporting 

period.

(6) For each storage vessel affected facility, the 

information in paragraphs (b)(6)(i) through (b)(6)(iv) of this 

section.

(i) An identification of each storage vessel with VOC 

emissions greater than 6 tpy installed, modified or 

reconstructed during the reporting period.

(ii) If required to reduce emissions by complying with 

§60.5395(a)(1), the records specified in §63.774(b)(2) through 

(b)(8) of this chapter.

(iii) Documentation that the VOC emission rate is less than 

6 tpy for meeting the requirements in §60.5395(a).

(iv) Records of deviations specified in paragraph 

(c)(5)(iii) of this section that occurred during the reporting 

period.

(7)(i) Within 60 days after the date of completing each 

performance test(see §60.8 of this part) as required by this 

subpart you must submit the results of the performance tests 

required by this subpart to EPA’s WebFIRE database by using the 

Compliance and Emissions Data Reporting Interface (CEDRI) that 

is accessed through EPA’s Central Data Exchange (CDX)

(www.epa.gov/cdx). Performance test data must be submitted in 
Page 309 of 497

the file format generated through use of EPA’s Electronic 

Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/index.html). Only data 

collected using test methods on the ERT website are subject to 

this requirement for submitting reports electronically to 

WebFIRE. Owners or operators who claim that some of the 

information being submitted for performance tests is 

confidential business information (CBI) must submit a complete 

ERT file including information claimed to be CBI on a compact 

disk or other commonly used electronic storage media (including, 

but not limited to, flash drives) to EPA. The electronic media 

must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE 

CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 

Old Page Rd., Durham, NC 27703. The same ERT file with the CBI 

omitted must be submitted to EPA via CDX as described earlier in 

this paragraph. At the discretion of the delegated authority, 

you must also submit these reports, including the confidential 

business information, to the delegated authority in the format 

specified by the delegated authority.

(ii) All reports required by this subpart not subject to 

the requirements in paragraphs (1)(i) of this section must be 

sent to the Administrator at the appropriate address listed in 

§63.13 of this part. The Administrator or the delegated 

authority may request a report in any form suitable for the 
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specific case (e.g., by commonly used electronic media such as 

Excel spreadsheet, on CD or hard copy). The Administrator 

retains the right to require submittal of reports subject to 

paragraph (1)(i) and (ii) of this section in paper format.

(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 well affected facility as 

specified in paragraphs (c)(1)(i) through (c)(1)(iii) of this 

section.

(i) Records identifying each well completion operation for 

each gas well affected facility conducted during the reporting 

period;

(ii) Records 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 well 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.

(A) For each gas wells 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 
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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 well 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.

(iv) For each gas well facility for which you claim an 

exception under §60.5375(a)(3), you must record: the location of 

the well; the specific exception claimed; the starting date and 

ending date for the period the well operated under the 

exception; and an explanation of why the well meets the claimed 

exception.

(2) For each centrifugal compressor affected facility, you 

must maintain records of deviations in cases where the 

centrifugal compressor was not operated in compliance with the 

requirements specified in §60.5380.

(3) For each reciprocating compressors affected facility, 

you must maintain the records in paragraphs (c)(3)(i) through

(c)(3)(iii) of this section.

(i) Records of the cumulative number of hours of operation

or number of months since initial startup or [INSERT DATE OF 
Page 312 of 497

PUBLICATION 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.

(iii) Records of deviations in cases where the reciprocating 

compressor was not operated in compliance with the requirements 

specified in §60.5385.

(4) For each pneumatic controller, you must maintain the 

records identified in paragraphs (c)(4)(i) through (c)(4)(v) 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 pneumatic 

controller affected facilities with a natural gas bleed rate 

greater than 6 standard cubic feet per hour are required and the 

reasons why.

(iii) If the pneumatic controller is not located at a 

natural gas processing plant, records of the manufacturer’s 

specifications indicating that the controller is designed such 

that natural gas bleed rate is less than or equal to 6 standard 

cubic feet per hour.
Page 313 of 497

(iv) If the pneumatic controller is located at a natural 

gas processing plant, records of the documentation that the 

natural gas bleed rate is zero.

(v) Records of deviations in cases where the pneumatic 

controller was not operated in compliance with the requirements 

specified in §60.5390.

(5) For each storage vessel affected facility, you must 

maintain the records identified in paragraphs (c)(5)(i) through

(c)(5)(iii) of this section.

(i) If required to reduce emissions by complying with 

§60.5395, the records specified in §63.774(b)(2) through (8) of 

this chapter.

(ii) Records of the determination that the VOC emission 

rate is less than 6 tpy per storage vessel for the exemption 

under §60.5395(a).

(iii) Records of deviations in cases where the storage 

vessel was not operated in compliance with the requirements 

specified in §§60.5395, 60.5411, 60.5412, and 60.5413.

§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.
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 (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 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.
Page 315 of 497

 (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.

 (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)(2)(i) through (iv), and (c)(2)(vii) 

through (viii).
Page 316 of 497

(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 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.
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(b) You must submit a 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) 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 of H2S expressed 

as sulfur.
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(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.

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.
Page 319 of 497

Alaskan North Slope means the approximately 69,000 squaremile 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.

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.

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 
Page 320 of 497

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.

Custody transfer means the transfer of natural gas after 

processing and/or treatment in the producing operations, or from 

storage vessels or automatic transfer facilities or other such 

equipment, including product loading racks, to pipelines or any 

other forms of transportation.

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).

Delineation well means a well drilled in order to determine 

the boundary of a field or producing reservoir.

Equipment means each pump, pressure relief device, openended valve or line, valve, compressor, and flange or other 

connector that is in VOC service or in wet gas service, and any 

device or system required by this subpart.
Page 321 of 497

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 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 products.

Gas well or natural gas well means an onshore well drilled 

principally for production of natural gas.

Hydraulic fracturing means process of directing pressurized 

liquids, containing water, proppant, and any added chemicals, to 

penetrate tight formations, such as sand, shale, or coal 
Page 322 of 497

formations, that involve high rate, extended back flow to expel 

fracture fluids and sand during completions. 

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 

equipment contains or contacts the field gas before the 

extraction step at a gas processing plant process unit.

Intermittent/snap-action pneumatic controller means a 

pneumatic controller that vents non-continuously.

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 non-toxic. 

Low pressure well means a well with reservoir pressure and 

vertical well depth such that 0.443 times the reservoir pressure 

(in psia) minus 0.092 times the vertical well depth (in feet) 

plus 497 psia is less than the sales line pressure at the sales 

meter.

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. 
Page 323 of 497

Natural gas-driven pneumatic controller means a pneumatic 

controller powered by pressurized natural gas.

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.

Natural gas transmission means the pipelines used for the 

long distance transport of natural gas (excluding processing). 

Specific equipment used in natural gas transmission includes the 

land, mains, valves, meters, boosters, regulators, storage 

vessels, dehydrators, compressors, and their driving units and 

appurtenances, and equipment used for transporting gas from a 

production plant, delivery point of purchased gas, gathering 

system, storage area, or other wholesale source of gas to one or 

more distribution area(s).

Nonfractionating plant means any gas plant that does not 

fractionate mixed natural gas liquids into natural gas products.

Non natural gas-driven pneumatic controller means an 

instrument that is actuated using other sources of power than 

pressurized natural gas; examples include solar, electric, and 

instrument air.
Page 324 of 497

Onshore means all facilities except those that are located 

in the territorial seas or on the outer continental shelf.

Pneumatic controller means an automated instrument used for 

maintaining a process condition such as liquid level, pressure, 

delta-pressure and temperature.

Pressure vessel means a storage vessel that is used to 

store liquids or gases and is designed not to vent to the 

atmosphere as a result of compression of the vapor headspace in 

the pressure vessel during filling of the pressure vessel to its 

design capacity.

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 
Page 325 of 497

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, 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).

Responsible official means one of the following:

(1) For a corporation: a president, secretary, treasurer, 

or vice-president of the corporation in charge of a principal 

business function, or any other person who performs similar 

policy or decision-making functions for the corporation, or a 

duly authorized representative of such person if the 

representative is responsible for the overall operation of one 

or more manufacturing, production, or operating facilities 

applying for or subject to a permit and either:

(i) The facilities employ more than 250 persons or have 

gross annual sales or expenditures exceeding $25 million (in 

second quarter 1980 dollars); or
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(ii) The delegation of authority to such representatives is 

approved in advance by the permitting authority;

(2) For a partnership or sole proprietorship: a general 

partner or the proprietor, respectively;

(3) For a municipality, State, Federal, or other public 

agency: Either a principal executive officer or ranking elected 

official. For the purposes of this part, a principal executive 

officer of a Federal agency includes the chief executive officer 

having responsibility for the overall operations of a principal 

geographic unit of the agency (e.g., a Regional Administrator of 

EPA); or

(4) For affected facilities:

(i) The designated representative in so far as actions, 

standards, requirements, or prohibitions under title IV of the 

Clean Air Act or the regulations promulgated thereunder are 

concerned; or

(ii) The designated representative for any other purposes 

under part 60.

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 
Page 327 of 497

materials that are not regulated materials and/or incorporated 

into a product; and/or recovered.

Salable quality gas means natural gas that meets the 

composition, moisture, or other limits set by the purchaser of 

the natural gas.

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.

Storage vessel means a unit that is constructed primarily 

of nonearthen materials (such as wood, concrete, steel, 

fiberglass, or plastic) which provides structural support and is 

designed to contain an accumulation of liquids or other 

materials. The following are not considered storage vessels:

(1) Vessels that are skid-mounted or permanently attached 

to a motor vehicle, such as trucks, railcars, barges or ships, 

and are located at a site for less than 180 days.

(2) Process vessels such as surge control vessels, bottoms 

receivers, or knockout vessels.

(3) Pressure vessels designed to operate in excess of 204.9 

kilopascals and without emissions to the atmosphere.

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.
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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.

Sweetening unit means a process device that removes 

hydrogen sulfide and/or carbon dioxide from the natural gas 

stream. 

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.

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)).

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 
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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 begins with the flowback 

immediately following hydraulic fracturing or refracturing and 

ends when either (1) the well is shut in, or (2) the well is 

continuously producing to the sales line.

Well completion operation means any well completion with 

hydraulic fracturing or well recompletion with hydraulic 

fracturing occurring at a gas well 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 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. 
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Table 1 to Subpart OOOO of part 60 – 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 to Subpart OOOO of part 60 – 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 or 97.9, whichever 

is smaller

97.5

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.
Page 331 of 497

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

§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 
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§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 Except that §60.18 

does not apply to 

flares.

§60.19 General 

notification and 

reporting 

requirement

Yes
Page 333 of 497

PART 63--[Amended]

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)(69), (b)(70), (b)(71) and (b)(72); 

and

b. Revising paragraph (i)(1) to read as follows:

§63.14 Incorporations by reference.

* * * * *

(b) * * *

* * * * *

(69) ASTM D1945 – 03(2010) Standard Test Method for 

Analysis of Natural Gas by Gas Chromatography, IBR approved for 

§§63.772 and 63.1282. 

(70) 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.

(71) 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.
Page 334 of 497

(72) 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;

b. Revising paragraph (a)(1)(iii);

c. Revising paragraph (a)(2);

d. Revising paragraph (b)(1)(i); 

e. Revising paragraph (b)(1)(ii);

f. Revising paragraph (f) introductory text;
Page 335 of 497

g. Revising paragraph (f)(1);

h. Revising paragraph (f)(2); and

i. Adding paragraphs (f)(7), (f)(8), and (f)(9) 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 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 
Page 336 of 497

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 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.

* * * * *

(b) * * *

(1) * * *

(i) Each glycol dehydration unit as specified in paragraphs 

(b)(1)(i)(A) through (C) of this section.

(A) Each large glycol dehydration unit;
Page 337 of 497

(B) Each small glycol dehydration unit for which 

construction commenced before August 23, 2011, is an existing 

small glycol dehydration unit; and

(C) Each small glycol dehydration unit for which 

construction commenced on or after August 23, 2011, is a new 

small glycol dehydration unit.

(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)(9) 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.

(1) Except as specified in paragraphs (f)(7) through (9) 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 
Page 338 of 497

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 (9) 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 

sources shall comply with the provisions of this standard 

immediately upon becoming a major source.

* * * * *

(7) Each affected existing 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 before 

August 23, 2011, must achieve compliance no later than [INSERT 

DATE THREE YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], except as provided in §63.6(i).

(8) Each affected new 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, 
Page 339 of 497

located at a major source, that commenced construction on or 

after August 23, 2011, must achieve compliance immediately upon 

initial startup or [INSERT DATE 60 DAYS AFTER DATE OF 

PUBLICATION IN THE FEDERAL REGISTER], whichever is later.

(9) A production field facility, as defined in §63.761, 

constructed before August 23, 2011, that was previously 

determined to be an area source but becomes a major source (as 

defined in paragraph 3 of the major source definition in 

§63.761) on the [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER] must achieve compliance no later than [INSERT DATE 3 

YEARS AFTER DATE OF PUBLICATION 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,” “responsible official” and “small glycol 

dehydration units”;

b. Revising the definitions for “associated equipment,” 

“glycol dehydration unit baseline operations,” “storage vessel,” 

and “temperature monitoring device”; and

c. Revising paragraph (3) of the definition for “major 

source” to read as follows:

§63.761 Definitions.
Page 340 of 497

* * * * *

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.

* * * * *

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 August 23, 2011. For the purposes of this 

subpart, for determining the percentage of overall HAP emission 
Page 341 of 497

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.

* * * * *

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.

* * * * *

Responsible official means one of the following:
Page 342 of 497

(1) For a corporation: a president, secretary, treasurer, 

or vice-president of the corporation in charge of a principal 

business function, or any other person who performs similar 

policy or decision-making functions for the corporation, or a 

duly authorized representative of such person if the 

representative is responsible for the overall operation of one 

or more manufacturing, production, or operating facilities 

applying for or subject to a permit and either:

(i) The facilities employ more than 250 persons or have 

gross annual sales or expenditures exceeding $25 million (in 

second quarter 1980 dollars); or

(ii) The delegation of authority to such representatives is 

approved in advance by the permitting authority;

(2) For a partnership or sole proprietorship: a general 

partner or the proprietor, respectively;

(3) For a municipality, State, Federal, or other public 

agency: Either a principal executive officer or ranking elected 

official. For the purposes of this part, a principal executive 

officer of a Federal agency includes the chief executive officer 

having responsibility for the overall operations of a principal 

geographic unit of the agency (e.g., a Regional Administrator of 

EPA); or

(4) For affected sources:
Page 343 of 497

(i) The designated representative in so far as actions, 

standards, requirements, or prohibitions under title IV of the 

Act or the regulations promulgated thereunder are concerned; and

(ii) The designated representative for any other purposes 

under part 70.

* * * * *

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).

* * * * *

Storage vessel means a tank or other vessel that is 

designed to contain an accumulation of crude oil, condensate, 

intermediate hydrocarbon liquids, or produced water and that is 

constructed primarily of non-earthen materials (e.g., wood, 

concrete, steel, plastic) that provide structural support. The 

following process units are not considered storage vessels:

surge control vessels and knockout vessels.

* * * * *

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 degrees C, or 

±2.8 degrees C, whichever is greater. The temperature monitoring 
Page 344 of 497

device may measure temperature in degrees Fahrenheit or degrees 

Celsius, or both. 

* * * * *

12. Section 63.762 is revised to read as follows:

§63.762 Malfunctions.

(a) The provisions set forth in this subpart shall apply at 

all times.

(b) [Reserved]

(c) [Reserved]

(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, 
Page 345 of 497

process equipment, or a process to operate in a normal or usual 

manner; and 

(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. Offshift 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 
Page 346 of 497

(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 avail itself of an affirmative 

defense to civil penalties for that malfunction. The owner or 

operator seeking to assert an affirmative defense shall also 
Page 347 of 497

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)(1) introductory text; 

c. Revising paragraph (i); and

d. Adding paragraph (j) to read as follows:

§63.764 General standards.

* * * * *

(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.

* * * * *
Page 348 of 497

(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 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 
Page 349 of 497

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);

c. Revising paragraph (c)(2); and

d. Revising paragraph (c)(3) 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 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(d).
Page 350 of 497

(ii) The owner or operator of a large glycol dehydration 

unit shall connect the process vent to a control device or 

combination of control devices through a closed-vent system and 

the outlet benzene emissions from the control device(s) shall be 

reduced to a level less than 0.90 megagrams per year. The 

closed-vent system shall be designed and operated in accordance 

with the requirements of §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 existing 

small glycol dehydration unit process vent, as defined in 

§63.761, to the limit determined in Equation 1 of this section. 

You must limit BTEX emissions from each new small glycol 

dehydration unit process vent, as defined in §63.761, to the 

limit determined in Equation 2 of this section. The limits 

determined using Equation 1 or Equation 2 must be met in 

accordance with one of the alternatives specified in paragraphs 

(b)(1)(iii)(A) through (D) of this section.

 Equation 1

Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per year;

3.28x10-4 = BTEX emission limit, grams BTEX/standard cubic meter 

-ppmv;

Throughput = Annual average daily natural gas throughput, 

standard cubic meters per day
Page 351 of 497

Ci,BTEX = average annual BTEX concentration of the natural gas at 

the inlet to the glycol dehydration unit, ppmv.

 Equation 2

Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per year;

4.66x10-6 = BTEX emission limit, grams BTEX/standard cubic meter 

-ppmv;

Throughput = Annual average daily natural gas throughput, 

standard cubic meters per day

Ci,BTEX = average annual 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 
Page 352 of 497

requirements specified in §63.771(e) and emissions in accordance 

with the requirements specified in §63.772(b)(2).

* * * * *

(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) through (iv) 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.
Page 353 of 497

(ii) For any large glycol dehydration unit, benzene 

emissions are reduced to a level less than 0.90 megagrams per 

year.

(iii) For each existing small glycol dehydration unit, BTEX 

emissions are reduced to a level less than the limit calculated 

by Equation 1 of paragraph (b)(1)(iii) of this section.

(iv) For each new small glycol dehydration unit, BTEX 

emissions are reduced to a level less than the limit calculated 

by Equation 2 of 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);

d. Adding paragraph (b)(3); and

e. 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) through (3) 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 
Page 354 of 497

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).

* * * * *

(3) The owner or operator shall control air emissions by 

connecting the cover, through a closed-vent system that meets 

the conditions specified in §63.771(c), to a process natural gas 

line.

* * * * *

(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 

subpart OOOO; or is subject to and controlled under 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) introductory text; 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 
Page 355 of 497

controlled under the requirements specified in subpart H of this 

part; or is subject to and controlled under the requirements 

specified in 40 CFR part 60, subpart KKK or subpart OOOO.

(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, §§61.241 through 61.247, 

except as specified in paragraphs (c)(1) through (8) of this 

section, except for valves subject to §61.242-7(b) a leak is 

detected if an instrument reading of 500 ppm or greater is 

measured. When a leak is detected from a valve it shall be 

repaired in accordance with the schedule in §61.242-7(d), or by 

[INSERT DATE 1 YEAR AFTER THE DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], whichever is later.

* * * * *

(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 the heading of paragraph (d);

c. Adding paragraph (d) introductory text;

d. Revising paragraph (d)(1)(i)(C);

e. Revising paragraph (d)(1)(ii);

f. Revising paragraph (d)(1)(iii);
Page 356 of 497

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:

§63.771 Control equipment requirements.

* * * * *

(c) Closed-vent system requirements. (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 device 

requirements in paragraph (f) of this section. 

(1) * * *

(i) * * *

(C) Operates at a minimum temperature of 760 degrees C, 

provided the control device has demonstrated, under §63.772(e), 

that combustion zone temperature is an indicator of control 

efficiency.

* * * * *
Page 357 of 497

(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.

* * * * *

(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 
Page 358 of 497

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 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 
Page 359 of 497

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 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 
Page 360 of 497

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 meet the levels 

specified in paragraphs (f)(1)(i)(A) or (B) of this section. 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.

(A) The mass content of BTEX in the gases vented to the 

device is reduced as determined in accordance with the 

requirements of §63.772(e).

(B) The concentration of either TOC or total HAP in the 

exhaust gases at the outlet of the device is reduced to a level 

equal to or less than 20 parts per million by volume on a dry 

basis corrected to 3 percent oxygen as determined in accordance 

with the requirements of §63.772(e). 

(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).

(iii) A flare, as defined in §63.761, that is designed and 

operated in accordance with the requirements of §63.11(b).
Page 361 of 497

(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).

(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 paragraph (c)(6)(i);

e. Adding paragraph (d);

f. Revising paragraph (e) introductory text;

g. Revising paragraphs (e)(1)(i) through (v);

h. Revising paragraph (e)(2);
Page 362 of 497

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) and (vi);

m. Revising paragraph (e)(4) introductory text;

n. Revising paragraph (e)(4)(i);

o. Revising paragraph (e)(5);

p. Revising paragraph (f) introductory text;

q. Revising paragraph (f)(2) and paragraph (f)(3);

r. Adding paragraphs (f)(4) through (f)(6);

s. Revising paragraph (g) introductory text;

t. Revising paragraph (g)(1) and paragraph (g)(2) 

introductory text;

u. Revising paragraph (g)(2)(iii); 

v. Revising paragraph (g)(3); 

w. Adding paragraph (h); and

x. 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 
Page 363 of 497

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 (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 GRI-GLYCalcTM , Version 

3.0 or higher, and the procedures presented in the associated 

GRI-GLYCalcTM Technical Reference Manual. Inputs to the model 

shall be representative of actual operating conditions of the 

glycol dehydration unit and may be determined using the 

procedures documented in the Gas Research Institute (GRI) report 

entitled “Atmospheric Rich/Lean Method for Determining Glycol 

Dehydrator Emissions” (GRI–95/0368.1); or

(ii) The owner or operator shall determine an average mass 

rate of benzene 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 
Page 364 of 497

emissions in kilograms per year shall be determined by 

multiplying the mass rate by the number of hours the unit is 

operated per year. This result shall be converted to megagrams 

per year.

* * * * *

(c) * * *

(6) * * *

(i) Except as provided in paragraph (c)(6)(ii) of this 

section, the detection instrument shall meet the performance 

criteria of Method 21 of 40 CFR part 60, appendix A, except the 

instrument response factor criteria in section 3.1.2(a) of 

Method 21 shall be for the average composition of the process 

fluid, not each individual volatile organic compound in the 

stream. For process streams that contain nitrogen, air, or other 

inert gases that are not organic hazardous air pollutants or 

volatile organic compounds, the average stream response factor 

shall be calculated on an inert-free basis.

* * * * *

(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 
Page 365 of 497

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 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 
Page 366 of 497

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 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.

(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 
Page 367 of 497

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);

(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, 
Page 368 of 497

subpart O; or has certified compliance with the interim status 

requirements of 40 CFR part 265, subpart O.

* * * * *

(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 

§63.771(d)(1)(i)(B), or the BTEX emission limit specified in 

§63.765(b)(1)(iii) the sampling site shall be located at the 

outlet of the combustion device.

* * * * *

(iv) * * *

(C) * * *
Page 369 of 497

(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 §63.765(b)(1)(iii) 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 intervals in time, 

such as 15-minute intervals during the run.

(B) The mass rate of BTEX (Eo) shall be computed using the 

equations and procedures specified in paragraphs (e)(3)(v)(B)(1) 

and (2) of this section. 

(1) The following equation shall be used:
Page 370 of 497

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-mole.

Qo= Flowrate of gas stream at the outlet of the control device, 

dry standard cubic meter per minute.

K2= 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) 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)(1) of this 

section.

(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 

[INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION IN THE FEDERAL 
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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 [INSERT DATE 3 

YEARS AFTER DATE OF PUBLICATION 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) 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.
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(1) A control device whose model is tested under, and meets 

the criteria of, §63.772(h), or

(2) A combustion control device demonstrating during the 

performance test under §63.772(e) that combustion zone 

temperature is an indicator of destruction efficiency and 

operates at a minimum temperature of 760 degrees C.

(4) For a condenser design analysis conducted to meet the 

requirements of §63.771(d)(1), (e)(3)(ii), or (f)(1), 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 
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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.

(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 with 
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§63.773(d)(4) except that the inlet gas flowrate 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 flowrate, 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 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.
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(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 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 site-specific 

condenser performance curve according to §63.773(d)(5)(ii). For 

sources required to meet the BTEX limit in accordance with 
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§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 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 
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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).

(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). 
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(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 

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 one-hour (or 

longer) test runs for each of the four following firing rate 

settings making a total of 12 test runs per test. Propene 
Page 379 of 497

(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. During the first 

5 minutes, incrementally 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, incrementally 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. During the first 

5 minutes, incrementally 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, incrementally 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. During the first 5 

minutes, incrementally ramp the firing rate to 30 percent of the 

maximum design rate. Hold at 30 percent for 5 minutes. In the 

10-15 minute time range, incrementally ramp back down to 0 
Page 380 of 497

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 

(h)(8)(iii) of this section.

(4) Inlet testing shall be conducted as specified in 

paragraphs (h)(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 flowrate 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 flowrate 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.
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(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 each THC run.

(2) Fill one canister across the three test runs for each 

THC test such that one composite fuel sample exists for each 

test condition.

(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) Higher heating value using ASTM D3588-98 or ASTM D4891-

89.
Page 382 of 497

(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) Flowrate 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 or other pressure measurement device shall 

be used to obtain an accurate flow profile.

(ii) Molecular weight shall be determined as specified in 

paragraphs (h)(4)(iii)(B), (h)(5)(ii)(A), and (h)(5)(ii)(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 
Page 383 of 497

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 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-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 
Page 384 of 497

part 60, Appendix A, integrated bag sample during the port 

change.

(iii) 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.

(iv) 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.

(v) Excess air shall be determined using resultant data 

from the EPA Method 3C tests and EPA Method 3B, 40 CFR part 60, 

Appendix A, equation 3B-1.

(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 each test.
Page 385 of 497

(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 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
Page 386 of 497

(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 

(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.

(D) Excess combustion air shall be equal to or greater than 

150 percent.

(ii) The manufacturer shall determine a maximum inlet gas 

flowrate 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 paragraphs 

(h)(7)(i)(A) through (C) of this section will have demonstrated 

a destruction efficiency of 95.0 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) of this section 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.
Page 387 of 497

(iii) Test fuel gas flow range (in both mass and volume). 

Include the minimum and maximum allowable inlet gas flowrate.

(iv) Air/stream injection/assist ranges, if used.

(v) The test parameter ranges listed in paragraphs (h)(8)(v)(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 flowrate.

(O) Wind velocity and direction.

(vi) The test report shall include all calibration quality 

assurance/quality control data, calibration gas values, gas 
Page 388 of 497

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 flowrate shall meet the range specified 

by the manufacturer. Flowrate shall be calculated 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 2 minutes during any 

hour. A visible emissions test using Method 22, 40 CFR part 60, 

Appendix A, shall be performed each calendar quarter. The 

observation period shall be 1 hour and shall be conducted 

according to EPA Method 22, 40 CFR part 60, Appendix A. 
Page 389 of 497

(4) Compliance with the operating parameter limit is 

achieved when the following criteria are met:

(i) The inlet gas flowrate 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 1 minute during the 

observation period. Devices failing the visible emissions test 

shall follow manufacturers repair instructions, if available, or 

best combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant 

operation. All repairs and maintenance activities for each unit 

shall be recorded in a maintenance and repair log and shall be 

available on site for inspection.

 (iv) Following return to operation from maintenance or 

repair activity, each device must pass a Method 22 observation 

as described in paragraph (i)(3) of this section. 

19. Section 63.773 is amended by:

a. Adding paragraph (b);

b. Revising paragraph (d)(1) introductory text;

c. Revising paragraph (d)(1)(ii) and adding paragraphs 

(d)(1)(iii) and (iv);
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d. Revising paragraph (d)(2);

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);

l. Revising paragraphs (d)(5)(ii)(A) through (C);

m. Revising paragraph (d)(6) introductory text;

n. Revising paragraphs (d)(6)(ii) and (iii);

o. Adding paragraph (d)(6)(vi);

p. Revising paragraph (d)(7); and

q. Removing paragraphs (d)(8) and (d)(9) to read as 

follows:

§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 
Page 391 of 497

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 (7) 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 

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 
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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 

site-specific 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).

(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 site-specific 

monitoring plan.
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(2) An owner or operator is exempt from the monitoring 

requirements specified in paragraphs (d)(3) through (7) of this 

section for the following types of control devices:

(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

(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 ±2.8 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 
Page 394 of 497

locations and have a minimum accuracy of ±1 percent of the 

temperature being monitored in degrees C, or ±2.8 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 

±2.8 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) * * *
Page 395 of 497

(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 flowrate 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 ±2.8 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 based on the 
Page 396 of 497

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) The owner or operator shall determine actual average 

inlet waste gas flowrate using the model GRI-GLYCalcTM , Version 

3.0 or higher, ProMax, or AspenTech HYSYS. Inputs to the models 

shall be representative of actual operating conditions of the 

controlled unit. The determination shall be performed to 

coincide with the visible emissions test under §63.772(i)(3); 

(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.
Page 397 of 497

(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 

§63.771(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 

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 
Page 398 of 497

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 flowrate 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 §63.772(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 
Page 399 of 497

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)(vi) 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)(vi) of this 

section, then a single excursion is determined to have occurred 

for the control device for that operating day.

* * * * *

(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 
Page 400 of 497

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(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 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 flowrate exceeds the maximum established 

during the test conducted under §63.772(h).

(B) Failure of the quarterly visible emissions test 

conducted under §63.772(i)(3) occurs. 

(7) For each excursion, the owner or operator shall be 

deemed to have failed to have applied control in a manner that 

achieves the required operating parameter limits. Failure to 
Page 401 of 497

achieve the required operating parameter limits is a violation 

of this standard.

* * * * *

20. Section 63.774 is amended by:

a. Revising paragraph (b)(3) introductory text;

b. Removing and reserving paragraph (b)(3)(ii);

c. Revising paragraph (b)(4)(ii) introductory text;

d. Adding paragraph (b)(4)(ii)(C);

e. Revising paragraph (b)(4)(iii);

f. Adding paragraph (b)(7)(ix); and

g. Adding paragraphs (g) through (i) 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 such periods and any other periods during 

process or control device operation when monitors are not 

operating or failed to collect required data.
Page 402 of 497

* * * * *

(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 a control device whose model is tested under 

§63.772(h), the records required in paragraph (h) of this 

section.

(iii) Hourly records of the times and durations of all 

periods when the vent stream is diverted from the control device 

or the device is not operating.

* * * * *

(7) * * *

(ix) Records identifying the carbon replacement schedule 

under §63.771(d)(5) and records of each carbon replacement.

* * * * *

(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 
Page 403 of 497

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 calculations 

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 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. Removing and reserving paragraph (b)(7);
Page 404 of 497

d. Revising paragraph (c)(1);

e. Revising paragraph (c)(6);

f. Revising paragraph (c)(7)(i);

g. Revising paragraph (d)(1)(i);

h. Revising paragraph (d)(1)(ii) introductory text;

i. Revising paragraph (d)(5)(ii);

j. Adding paragraph (d)(5)(iv);

k. Revising paragraph (d)(11);

l. Adding paragraphs (d)(13) and (d)(14);

m. Revising paragraphs (e)(2) introductory text,

(e)(2)(ii)(B) and (C);

n. Adding paragraphs (e)(2)(ii)(E) and (F);

o Adding paragraphs (e)(2)(xi) through (xiii); and

p. Adding paragraph (g) to read as follows:

§63.775 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 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 
Page 405 of 497

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 [INSERT DATE ONE YEAR AFTER DATE OF PUBLICATION 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 [INSERT DATE THREE YEARS AFTER DATE OF PUBLICATION 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 
Page 406 of 497

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 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 
Page 407 of 497

accordance with §63.764(j), including actions taken to correct a 

malfunction.

(7) * * *

(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) * * *

(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 (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 
Page 408 of 497

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 unless the test 

results for that model of combustion control device are posted 

at the following website: epa.gov/airquality/oilandgas/. 

* * * * *

(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 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 
Page 409 of 497

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 (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 the model of control device was tested by the 

manufacturer.

(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 (ix) of this section, 

as applicable.

* * * * *

(ii) * * *
Page 410 of 497

* * * * *

(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, 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 

flowrate 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, repairs affected to the 

unit, and date the unit was returned to service.

* * * * *

(xi) The results of any periodic test as required in 

§63.772(e)(3) conducted during the reporting period.
Page 411 of 497

(xii) For each carbon adsorber used to meet the control 

device requirements of §63.771(d)(1), records of 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).

(ix) Certification by a responsible official of truth, 

accuracy, and completeness. This certification shall state that, 

based on information and belief formed after reasonable inquiry, 

the statements and information in the document are true, 

accurate, and complete.

* * * * *

(g) Electronic reporting. (1) Within 60 days after the date 

of completing each performance test(defined in §63.2) as 

required by this subpart you must submit the results of the 

performance tests required by this subpart to EPA’s WebFIRE 

database by using the Compliance and Emissions Data Reporting 

Interface (CEDRI) that is accessed through EPA’s Central Data 

Exchange (CDX)(www.epa.gov/cdx). Performance test data must be 

submitted in the file format generated through use of EPA’s 

Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/index.html). Only data 

collected using test methods on the ERT website are subject to 

this requirement for submitting reports electronically to 
Page 412 of 497

WebFIRE. Owners or operators who claim that some of the 

information being submitted for performance tests is 

confidential business information (CBI) must submit a complete 

ERT file including information claimed to be CBI on a compact 

disk or other commonly used electronic storage media (including, 

but not limited to, flash drives) to EPA. The electronic media 

must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE 

CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 

Old Page Rd., Durham, NC 27703. The same ERT file with the CBI 

omitted must be submitted to EPA via CDX as described earlier in 

this paragraph. At the discretion of the delegated authority, 

you must also submit these reports, including the confidential 

business information, to the delegated authority in the format 

specified by the delegated authority. 

(2) All reports required by this subpart not subject to the 

requirements in paragraph (g)(1) of this section must be sent to 

the Administrator at the appropriate address listed in §63.13. 

The Administrator or the delegated authority may request a 

report in any form suitable for the specific case (e.g., by 

commonly used electronic media such as Excel spreadsheet, on CD 

or hard copy). The Administrator retains the right to require 

submittal of reports subject to paragraph (g)(1) of this section 

in paper format.
Page 413 of 497

22. Appendix to subpart HH of part 63 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

Applicable 

to 

subpart HH 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 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.
Page 414 of 497

§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.

§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.
Page 415 of 497

§63.6(g) Yes.

§63.6(h) Yes.

§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.

§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 
Page 416 of 497

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.

§63.9(c) Yes.

§63.9(d) Yes.

§63.9(e) Yes.

§63.9(f) Yes.

§63.9(g) 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 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 §63.774(g) for 

recordkeeping of occurrence, 
Page 417 of 497

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 on-site and 

allows offsite storage for the 

remaining 4 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 
Page 418 of 497

offset and UC boundaries are 

not required to submit reports.

§63.10(e)(3)(i)(A) Yes.

§63.10(e)(3)(i)(B) Yes.

§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.
Page 419 of 497

Subpart HHH–-[Amended]

23. Section 63.1270 is amended by:

a. Revising paragraph (a) introductory text;

b. Revising paragraph (a)(4);

c. Revising paragraph (b);

d. Revising paragraphs (d)(1) and (d)(2); and 

e. Adding paragraphs (d)(3) and (4) 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 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 
Page 420 of 497

§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.

* * * * *

(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 
Page 421 of 497

be the unit’s maximum rate under its physical and operational 

design consistent with the definition of potential to emit in 

§63.2.

(b) The affected source is each new and existing glycol 

dehydration unit specified in paragraphs (b)(1) through (3) of 

this section.

(1) Each large glycol dehydration unit;

(2) Each small glycol dehydration unit for which 

construction commenced before August 23, 2011, is an existing 

small glycol dehydration unit.

(3) Each small glycol dehydration unit for which 

construction commenced on or after August 23, 2011, is a new 

small glycol dehydration unit.

* * * * *

(d) * * *

(1) Except as specified in paragraphs (d)(3) through (4) 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) HAP such that the source becomes a major 
Page 422 of 497

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 (4) 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 August 23, 2011, must achieve compliance no 

later than [INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION 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 commenced 

construction on or after August 23, 2011, must achieve 

compliance immediately upon initial startup or [INSERT DATE 60 

DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER], 

whichever is later.

* * * * *

24. Section 63.1271 is amended by:
Page 423 of 497

a. Adding, in alphabetical order, new definitions for the 

terms “affirmative defense,” “BTEX,” “flare,” “large glycol 

dehydration units,” “responsible official” and “small glycol 

dehydration units”; and 

b. Revising the definitions for “glycol dehydration unit 

baseline operations” and “temperature monitoring device” to read 

as follows:

§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 August 23, 2011,. For the purposes of this 
Page 424 of 497

subpart, for determining the percentage of overall HAP emission 

reduction attributable to process modifications, glycol 

dehydration unit baseline operations shall be parameter values 

(including, but not limited to, glycol circulation rate or 

glycol-HAP absorbency) that represent actual long-term 

conditions (i.e., at least 1 year). Glycol dehydration units in 

operation for less than 1 year shall document that the parameter 

values represent expected long-term operating conditions had 

process modifications not been made.

* * * * *

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).

* * * * * 

Responsible official means one of the following:

(1) For a corporation: a president, secretary, treasurer, 

or vice-president of the corporation in charge of a principal 

business function, or any other person who performs similar 

policy or decision-making functions for the corporation, or a 

duly authorized representative of such person if the 

representative is responsible for the overall operation of one 
Page 425 of 497

or more manufacturing, production, or operating facilities 

applying for or subject to a permit and either:

(i) The facilities employ more than 250 persons or have 

gross annual sales or expenditures exceeding $25 million (in 

second quarter 1980 dollars); or

(ii) The delegation of authority to such representatives is 

approved in advance by the permitting authority;

(2) For a partnership or sole proprietorship: a general 

partner or the proprietor, respectively;

(3) For a municipality, State, Federal, or other public 

agency: Either a principal executive officer or ranking elected 

official. For the purposes of this part, a principal executive 

officer of a Federal agency includes the chief executive officer 

having responsibility for the overall operations of a principal 

geographic unit of the agency (e.g., a Regional Administrator of 

EPA); or

(4) For affected sources:

(i) The designated representative in so far as actions, 

standards, requirements, or prohibitions under title IV of the 

Act or the regulations promulgated thereunder are concerned; and

(ii) The designated representative for any other purposes 

under part 70.

* * * * *
Page 426 of 497

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).

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 degrees C, or 

±2.8 degrees C, whichever is greater. The temperature monitoring 

device may measure temperature in degrees Fahrenheit or degrees 

Celsius, or both.

* * * * * 

25. Section 63.1272 is revised to read as follows:

§63.1272 Malfunctions.

(a) The provisions set forth in this subpart shall apply at 

all times.

(b) [Reserved]

(c) [Reserved] 

(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 
Page 427 of 497

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 

(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. Offshift 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 
Page 428 of 497

(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 

(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.
Page 429 of 497

(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 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. Removing and reserving paragraph (d);

c. Revising paragraph (g); and
Page 430 of 497

d. Adding paragraph (h) to read as follows:

§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 pollution 

control equipment and monitoring equipment, in a manner 

consistent with safety and good air pollution control practices 
Page 431 of 497

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);

c. Revising paragraph (c)(2); and

d. Revising paragraph (c)(3) to read as follows:

§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 closed-vent system shall be designed and 

operated in accordance with the requirements of §63.1281(c). The 
Page 432 of 497

control device(s) shall be designed and operated in accordance 

with the requirements of §63.1281(d).

(ii) The owner or operator of a large glycol dehydration 

unit shall connect the process vent to a control device or a 

combination of control devices through a closed-vent system and 

the outlet benzene emissions from the control device(s) shall be 

less than 0.90 megagrams per year. The closed-vent system shall 

be designed and operated in accordance with the requirements of 

§63.1281(c). The control device(s) shall be designed and 

operated in accordance with the requirements of §63.1281(d), 

except that the performance requirements specified in 

§63.1281(d)(1)(i) and (ii) do not apply.

(iii) You must limit BTEX emissions from each existing 

small glycol dehydration unit, as defined in §63.1271, to the 

limit determined in Equation 1 of this section. You must limit 

BTEX emissions from each new small glycol dehydration unit

process vent, as defined in §63.1271, to the limit determined in 

Equation 2 of this section. The limits determined using Equation 

1 or Equation 2, of this section, must be met in accordance with 

one of the alternatives specified in paragraphs (b)(1)(iii)(A) 

through (D) of this section. 

 Equation 1

Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per year;
Page 433 of 497

3.72x10-4 = BTEX emission limit, grams BTEX/standard cubic meter 

-ppmv;

Throughput = Annual average daily natural gas throughput, 

standard cubic meters per day

Ci,BTEX = Annual average BTEX concentration of the natural gas at 

the inlet to the glycol dehydration unit, ppmv.

 Equation 2

Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per year;

1.10x10-5 = BTEX emission limit, grams BTEX/standard cubic meter 

-ppmv;

Throughput = Annual average daily natural gas throughput, 

standard cubic meters per day

Ci,BTEX = Annual average 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 §63.1281(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 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 
Page 434 of 497

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 levels specified in 

paragraph (c)(3)(i) through (iv) 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.
Page 435 of 497

(ii) For any large glycol dehydration unit, benzene 

emissions are reduced to a level less than 0.90 megagrams per 

year.

(iii) For each existing small glycol dehydration unit, BTEX 

emissions are reduced to a level less than the limit calculated 

in Equation 1 of paragraph (b)(1)(iii) of this section.

(iv) For each new small glycol dehydration unit, BTEX 

emissions are reduced to a level less than the limit calculated 

in Equation 2 of paragraph (b)(1)(iii) of this section.

28. Section 63.1281 is amended by:

a. Revising paragraph (c)(1);

b. Revising the heading of paragraph (d).

c. Adding paragraph (d) introductory text;

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:

§63.1281 Control equipment requirements.

* * * * *

(c) * * *
Page 436 of 497

(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) * * *

(C) Operates at a minimum temperature of 760 degrees C, 

provided the control device has demonstrated, under §63.1282(d), 

that combustion zone temperature is an indicator of control 

efficiency..

* * * * *

(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).
Page 437 of 497

* * * * *

(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) * * *

(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) * * *
Page 438 of 497

(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 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 
Page 439 of 497

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 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 meet the levels 

specified in paragraphs (f)(1)(i)(A) or (B) of this section. 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.
Page 440 of 497

(A) The mass content of BTEX in the gases vented to the 

device is reduced as determined in accordance with the 

requirements of §63.1282(d).

(B) The concentration of either TOC or total HAP in the 

exhaust gases at the outlet of the device is reduced to a level 

equal to or less than 20 parts per million by volume on a dry 

basis corrected to 3 percent oxygen as determined in accordance 

with the requirements of §63.1282(e).

(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).

(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 
Page 441 of 497

demonstrate compliance according to the requirements of either 

§63.1282(e) or (h).

(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);

d. Revising paragraph (b)(6)(i);

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;

q. Revising paragraphs (e)(2) and (e)(3); 
Page 442 of 497

r. Adding paragraphs (e)(4) through (e)(6);

s. Revising paragraph (f) introductory text;

t. Revising paragraph (f)(1);

u. Revising paragraph (f)(2) introductory text;

v. Revising paragraph (f)(2)(iii);

w. Revising paragraph (f)(3); and

x. 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 (a)(2)(ii) of this 

section. Emissions shall be determined either uncontrolled or 

with federally enforceable controls in place.
Page 443 of 497

(i) The owner or operator shall determine actual average 

benzene or BTEX emissions using the model GRI-GLYCalcTM, Version 

3.0 or higher, and the procedures presented in the associated 

GRI-GLYCalcTM Technical Reference Manual. Inputs to the model 

shall be representative of actual operating conditions of the 

glycol dehydration unit and may be determined using the 

procedures documented in the Gas Research Institute (GRI) report 

entitled “Atmospheric Rich/Lean Method for Determining Glycol 

Dehydrator Emissions” (GRI–95/0368.1); or

(ii) The owner or operator shall determine an average mass 

rate of benzene 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.

* * * * *

(b) * * *

(6) * * *

(i) Except as provided in paragraph (b)(6)(ii) of this 

section, the detection instrument shall meet the performance 

criteria of Method 21 of 40 CFR part 60, appendix A, except the 

instrument response factor criteria in section 3.1.2(a) of 
Page 444 of 497

Method 21 shall be for the average composition of the process 

fluid not each individual volatile organic compound in the 

stream. For process streams that contain nitrogen, air, or other 

inert gases that are not organic HAP or VOC, the average stream 

response factor shall be calculated on an inert-free basis.

* * * * *

(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 
Page 445 of 497

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.

(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 GRI-GLYCalcTM 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 devices. 

The owners or operators shall demonstrate that a control device 
Page 446 of 497

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);

(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 
Page 447 of 497

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.

* * * * *

(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 
Page 448 of 497

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) * * *

(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 §63.1275(b)(1)(iii) 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 
Page 449 of 497

§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 intervals in time, 

such as 15-minute intervals during the run.

(B) The mass rate of BTEX (Eo) shall be computed using the 

equations and procedures specified in paragraphs (d)(3)(v)(B)(1) 

and (2) of this section. 

(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-mole.

Qo= Flowrate of gas stream at the outlet of the control device, 

dry standard cubic meter per minute.

K2= 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) is 20 

degrees C.

n = Number of components in sample.
Page 450 of 497

(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 (d)(3)(v)(B)(1) of this 

section.

(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 

[INSERT DATE 3 YEARS AFTER DATE OF PUBLICATION 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 [INSERT DATE 3 

YEARS AFTER DATE OF PUBLICATION 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 
Page 451 of 497

except as specified in paragraphs (e)(3)(vi)(B)(1) 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 demonstrating during the 

performance test under §63.1282(d) that combustion zone 

temperature is an indicator of destruction efficiency and 

operates at a minimum temperature of 760 degrees C.

* * * * *

(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 
Page 452 of 497

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 Glycol Dehydrator 

Emissions,” (GRI–95/0368.1) as inputs for the model GRIGLYCalcTM, 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 
Page 453 of 497

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 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).
Page 454 of 497

(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 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 
Page 455 of 497

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 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 site-specific 

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.

* * * * *
Page 456 of 497

(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 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 
Page 457 of 497

of the calendar year, each year, until 30 days of condenser 

operating data are accumulated.

(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 or is equal to or greater than the minimum percent 

reduction necessary to meet the BTEX emission limit as 

determined in paragraph (f)(1) of this section.

* * * * *

(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.

* * * * *
Page 458 of 497

(g) 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 (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 one-hour (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. During the first 

5 minutes, incrementally 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, incrementally ramp back down to 70 

percent of the maximum design rate. Repeat three more times for 

a total of 60 minutes of sampling.
Page 459 of 497

(iii) 30 - 70 - 30 percent (ramp up, ramp down). Begin the 

test at 30 percent of the maximum design rate. During the first 

5 minutes, incrementally 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, incrementally 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. During the first 5 

minutes, incrementally ramp the firing rate to 30 percent of the 

maximum design rate. Hold at 30 percent for 5 minutes. In the 

10-15 minute time range, incrementally 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 

(g)(8)(iii) of this section.
Page 460 of 497

(4) Inlet testing shall be conducted as specified in 

paragraphs (g)(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 flowrate 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 flowrate 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 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 each THC test run.
Page 461 of 497

(2) Fill one canister across the three test runs for each 

THC test such that one composite fuel sample exists for each 

test condition.

(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) 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 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. 
Page 462 of 497

(B) Flowrate 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 or other pressure measurement device shall 

be used to obtain an accurate flow profile.

(ii) Molecular weight shall be determined as specified in 

paragraphs (g)(4)(iii)(B), and (g)(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 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-045 as 
Page 463 of 497

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.

(iii) 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.

(iv) 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 
Page 464 of 497

annotated with date and time, will be taken once per test run 

and the four photos included in the test report.

(v) Excess air shall be determined using resultant data 

from the EPA Method 3C tests and EPA Method 3B, 40 CFR part 60, 

Appendix A, equation 3B-1.

(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 test run.

(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).
Page 465 of 497

(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 (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.

(D) Excess combustion air shall be equal to or greater than 

150 percent. 

(ii) The manufacturer shall determine a maximum inlet gas 

flowrate which shall not be exceeded for each control device 

model to achieve the criteria in paragraph (g)(7)(i) of this 

section.
Page 466 of 497

(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 95.0 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 (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 flowrate.

(iv) Air/stream injection/assist ranges, if used.

(v) The test parameter ranges listed in paragraphs 

(g)(8)(v)(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.
Page 467 of 497

(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 flowrate.

(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 complying with the following 

criteria: 
Page 468 of 497

(1) The inlet gas flowrate shall meet the range specified 

by the manufacturer. Flowrate shall be calculated 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 2 minutes during any 

hour. A visible emissions test using Method 22, 40 CFR part 60, 

Appendix A, shall be performed each calendar quarter. The 

observation period shall be 1 hour and shall be used according 

to EPA Method 22, 40 CFR part 60, Appendix A. 

(4) Compliance with the operating parameter limit is 

achieved when the following criteria are met:

(i) The inlet gas flowrate 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 during the 

observation period. Devices failing the visible emissions test 

shall follow manufacturers repair instructions, if available, or 

best combustion engineering practice as outlined in the unit 
Page 469 of 497

inspection and maintenance plan, to return the unit to compliant 

operation. All repairs and maintenance activities for each unit 

shall be recorded in a maintenance and repair log and shall be 

available on site for inspection.

 (iv) Following return to operation from maintenance or 

repair activity, each device must pass a Method 22 observation 

as described in paragraph (h)(3) of this section.

30. Section 63.1283 is amended by:

a. Adding 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);

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);

l. Revising paragraphs (d)(5)(ii)(A) through (C);

m. Revising paragraph (d)(6) introductory text;

n. Revising paragraphs (d)(6)(ii);

o. Adding paragraph (d)(6)(v);
Page 470 of 497

p. Revising paragraph (d)(7)); and

q. Removing paragraph (d)(8) 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 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 (7) 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 
Page 471 of 497

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 §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 

site-specific 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;
Page 472 of 497

(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 site-specific 

monitoring plan.

(2) An owner or operator is exempted from the monitoring 

requirements specified in paragraphs (d)(3) through (7) of this 

section for the following types of control devices:

(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) * * *
Page 473 of 497

(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 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 

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 ±2.8 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 
Page 474 of 497

±2.8 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 sensitivity of 5 percent of 

the flowrate 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 
Page 475 of 497

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 ±2.8 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) The owner or operator shall determine actual average 

inlet waste gas flowrate using the model GRI-GLYCalcTM , Version 

3.0 or higher, ProMax, or AspenTech HYSYS. Inputs to the models 

shall be representative of actual operating conditions of the 

controlled unit. The determination shall be performed to 

coincide with the visible emissions test under §63.1282(h)(3); 

(2) A heat sensing monitoring device equipped with a 

continuous recorder that indicates the continuous ignition of 

the pilot flame.
Page 476 of 497

* * * * *

(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 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 
Page 477 of 497

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.

(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 flowrate 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 
Page 478 of 497

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 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 
Page 479 of 497

device and during the same operating day, and more than one of 

these operating parameters meets an excursion criterion 

specified in paragraphs (d)(6)(i) through (d)(6)(v) of this 

section, then a single excursion is determined to have occurred 

for the control device for that operating day.

* * * * *

(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 flowrate exceeds the maximum established 

during the test conducted under §63.1282(g).

(B) Failure of the quarterly visible emissions test 

conducted under §63.1282(h)(3) occurs.

(7) For each excursion, the owner or operator shall be 

deemed to have failed to have applied control in a manner that 

achieves the required operating parameter limits. Failure to 
Page 480 of 497

achieve the required operating parameter limits is a violation 

of this standard.

* * * * *

31. Section 63.1284 is amended by:

a. Revising paragraph (b)(3) introductory text;

b. Removing and reserving paragraph (b)(3)(ii);

c. Revising paragraph (b)(4)(ii);

d. Revising paragraph (b)(4)(iii);

e. Adding paragraph (b)(7)(ix); and

f. Adding paragraph (f), (g) and (h) to read as follows:

§63.1284 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 §63.1283(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.

* * * * *
Page 481 of 497

(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) 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.

(iii) Hourly records of the times and durations of all 

periods when the vent stream is diverted from the control device 

or the device is not operating.

* * * * *

(7) * * *

(ix) Records identifying the carbon replacement schedule 

under §63.1281(d)(5) and records of each carbon replacement.
Page 482 of 497

* * * * *

(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 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 calculations 

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.
Page 483 of 497

32. Section 63.1285 is amended by:

a. Revising paragraph (b)(1);

b. Revising paragraph (b)(6);

c. Removing paragraph (b)(7);

d. Revising paragraph (d) introductory text;

e. Revising paragraph (d)(1) introductory text;

f. Revising paragraph (d)(1)(i);

g. Revising paragraph (d)(1)(ii) introductory text;

h. Revising paragraph (d)(2) introductory text;

i. Revising paragraph (d)(4) introductory text;

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) * * *
Page 484 of 497

(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 (b)(1)(ii) 

of this section, the initial notification 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 §63.1270(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 [INSERT DATE ONE YEAR AFTER DATE OF PUBLICATION IN 

THE FEDERAL REGISTER], whichever is later. An affected source 

identified under §63.1270(d)(3) that plans to be an area source 

by [INSERT DATE THREE YEARS AFTER DATE OF PUBLICATION 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.

* * * * *
Page 485 of 497

(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 §63.1274(h), including actions taken to correct 

a malfunction.

* * * * *

(d) Each owner or operator of a source subject to this 

subpart shall submit a Notification of Compliance Status Report 

as required under §63.9(h) within 180 days after the compliance 

date specified in §63.1270(d). In addition to the information 

required under §63.9(h), the Notification of Compliance Status 

Report shall include the information specified in paragraphs 

(d)(1) through (12) of this section. This information may be 

submitted in an operating permit application, in an amendment to 

an operating permit application, in a separate submittal, or in 

any combination of the three. If all of the information required 

under this paragraph have been submitted at any time prior to 

180 days after the applicable compliance dates specified in 

§63.1270(d), a separate Notification of Compliance Status Report 
Page 486 of 497

is not required. If an owner or operator submits the information 

specified in paragraphs (d)(1) through (12) of this section at 

different times, and/or different submittals, subsequent 

submittals may refer to previous submittals instead of 

duplicating and resubmitting the previously submitted 

information.

(1) If a closed-vent system and a control device other than 

a flare are used to comply with §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 (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 
Page 487 of 497

shall be submitted via email to Oil_and_Gas_PT@EPA.GOV unless 

the test results for that model of combustion control device are 

posted at the following website: epa.gov/airquality/oilandgas/.

* * * * *

(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.

* * * * *

(4) For each control device other than a flare used to 

meet the requirements of §63.1274, the owner or operator shall 

submit the information specified in paragraphs (d)(4)(i) through 

(iv) of this section for each operating parameter required to be 

monitored in accordance with the requirements of §63.1283(d).* * 

* * *

(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).
Page 488 of 497

* * * * *

(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 

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 the model of control device was tested by the 

manufacturer.

(v) Manufacturer’s HAP destruction efficiency rating.
Page 489 of 497

(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 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 

flowrate 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, repairs affected to the 

unit, and date the unit was returned to service.
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* * * * *

(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 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).

(xiii) Certification by a responsible official of truth, 

accuracy, and completeness. This certification shall state that, 

based on information and belief formed after reasonable inquiry, 

the statements and information in the document are true, 

accurate, and complete.

* * * * *

(g) Electronic reporting. (1) Within 60 days after the date 

of completing each performance test (defined in §63.2) as 

required by this subpart you must submit the results of the 

performance tests required by this subpart to EPA’s WebFIRE 

database by using the Compliance and Emissions Data Reporting 

Interface (CEDRI) that is accessed through EPA’s Central Data 

Exchange (CDX)(www.epa.gov/cdx). Performance test data must be 

submitted in the file format generated through use of EPA’s 

Electronic Reporting Tool (ERT) (see 
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http://www.epa.gov/ttn/chief/ert/index.html). Only data 

collected using test methods on the ERT website are subject to 

this requirement for submitting reports electronically to 

WebFIRE. Owners or operators who claim that some of the 

information being submitted for performance tests is 

confidential business information (CBI) must submit a complete 

ERT file including information claimed to be CBI on a compact 

disk or other commonly used electronic storage media (including, 

but not limited to, flash drives) to EPA. The electronic media 

must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE 

CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 

Old Page Rd., Durham, NC 27703. The same ERT file with the CBI 

omitted must be submitted to EPA via CDX as described earlier in 

this paragraph. At the discretion of the delegated authority, 

you must also submit these reports, including the confidential 

business information, to the delegated authority in the format 

specified by the delegated authority.

(2) All reports required by this subpart not subject to the 

requirements in paragraph (g)(1) of this section must be sent to 

the Administrator at the appropriate address listed in §63.13. 

The Administrator or the delegated authority may request a 

report in any form suitable for the specific case (e.g., by 

commonly used electronic media such as Excel spreadsheet, on CD 

or hard copy). The Administrator retains the right to require 
Page 492 of 497

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:

§63.1287 Alternative means of emission limitation. 

(a) If, in the judgment of the Administrator, an 

alternative means of emission limitation will achieve a 

reduction in HAP emissions at least equivalent to the reduction 

in HAP emissions from that source achieved under the applicable 

requirements in §§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

subpart HHH

Explanation

§63.1(a)(1) Yes.

§63.1(a)(2) Yes.
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§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.

§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.
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§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) Yes.

§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.
Page 495 of 497

§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.

§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.
Page 496 of 497

§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) Yes.

§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 

(b)(2)(xiv)

Yes.

§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) 

through (c)(11)

No See §63.1284(f)for recordkeeping 

of malfunctions

§63.10(c)(12)

through (c)(14)

Yes.

§63.10(c)(15) No.
Page 497 of 497

§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.